Optimized well spacing for in situ shale oil development

ABSTRACT

A method for spacing heater wells for an in situ conversion process is provided. The method includes the steps of determining a direction along which thermal energy will travel most efficiently through a subsurface formation, and completing a plurality of heater wells in the subsurface formation, with the heater wells being spaced farther apart in the determined direction than in a direction transverse to the determined direction. In one aspect, the step of determining a direction along which thermal energy will travel most efficiently is performed based upon a review of geological data pertaining to the subsurface formation. The geological data may comprise the direction of least horizontal principal stress in the subsurface formation. Alternatively, the geological data may comprise the direction of bedding in the subsurface formation, the tilt of the subsurface formation relative to the surface topography, the organic carbon content of the kerogen, the initial formation permeability, and other factors.

STATEMENT OF RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional application60/851,541 which was filed on Oct. 13, 2006. The provisional applicationis incorporated herein in its entirety by reference.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention relates to the field of hydrocarbon recovery fromsubsurface formations. More specifically, the present invention relatesto the in situ recovery of hydrocarbon fluids from organic-rich rockformations, including, for example, oil shale formations, coalformations and tar sands formations. The present invention also relatesto the arrangement of wellbores in a shale oil development area.

2. Background of the Invention

Certain geological formations are known to contain an organic matterknown as “kerogen.” Kerogen is a solid, carbonaceous material. Whenkerogen is imbedded in rock formations, the mixture is referred to asoil shale. This is true whether or not the mineral is, in fact,technically shale, that is, a rock formed from compacted clay.

Kerogen is subject to decomposing upon exposure to heat over a period oftime. Upon heating, kerogen molecularly decomposes to produce oil, gas,and carbonaceous coke. Small amounts of water may also be generated. Theoil, gas and water fluids become mobile within the rock matrix, whilethe carbonaceous coke remains essentially immobile.

Oil shale formations are found in various areas world-wide, includingthe United States. Oil shale formations tend to reside at relativelyshallow depths. In the United States, oil shale is most notably found inWyoming, Colorado, and Utah. These formations are often characterized bylimited permeability. Some consider oil shale formations to behydrocarbon deposits which have not yet experienced the years of heatand pressure thought to be required to create conventional oil and gasreserves.

The decomposition rate of kerogen to produce mobile hydrocarbons istemperature dependent. Temperatures generally in excess of 270° C. (518°F.) over the course of many months may be required for substantialconversion. At higher temperatures substantial conversion may occurwithin shorter times. When kerogen is heated, chemical reactions breakthe larger molecules forming the solid kerogen into smaller molecules ofoil and gas. The thermal conversion process is referred to as pyrolysisor retorting.

Attempts have been made for many years to extract oil from oil shaleformations. Near-surface oil shales have been mined and retorted at thesurface for over a century. In 1862, James Young began processingScottish oil shales. The industry lasted for about 100 years. Commercialoil shale retorting through surface mining has been conducted in othercountries as well such as Australia, Brazil, China, Estonia, France,Russia, South Africa, Spain, and Sweden. However, the practice has beenmostly discontinued in recent years because it proved to be uneconomicalor because of environmental constraints on spent shale disposal. (See T.F. Yen, and G. V. Chilingarian, “Oil Shale,” Amsterdam, Elsevier, p.292, the entire disclosure of which is incorporated herein byreference.) Further, surface retorting requires mining of the oil shale,which limits application to very shallow formations.

In the United States, the existence of oil shale deposits innorthwestern Colorado has been known since the early 1900's. Whileresearch projects have been conducted in this area from time to time, noserious commercial development has been undertaken. Most research on oilshale production has been carried out in the latter half of the 1900's.The majority of this research was on shale oil geology, geochemistry,and retorting in surface facilities.

In 1947, U.S. Pat. No. 2,732,195 issued to Ljungstrom. That patent,entitled “Method of Treating Oil Shale and Recovery of Oil and OtherMineral Products Therefrom,” proposed the application of heat at hightemperatures to the oil shale formation in situ to distill and producehydrocarbons. The '195 Ljungstrom patent is incorporated herein byreference.

Ljungstrom coined the phrase “heat supply channels” to describe boreholes drilled into the formation. The bore holes received an electricalheat conductor which transferred heat to the surrounding oil shale.Thus, the heat supply channels served as heat injection wells. Theelectrical heating elements in the heat injection wells were placedwithin sand or cement or other heat-conductive material to permit theheat injection wells to transmit heat into the surrounding oil shalewhile preventing the inflow of fluid. According to Ljungstrom, the“aggregate” was heated to between 500° and 1,000° C. in someapplications.

Along with the heat injection wells, fluid producing wells were alsocompleted in near proximity to the heat injection wells. As kerogen waspyrolyzed upon heat conduction into the rock matrix, the resulting oiland gas would be recovered through the adjacent production wells.

Ljungstrom applied his approach of thermal conduction from heatedwellbores through the Swedish Shale Oil Company. A full scale plant wasdeveloped that operated from 1944 into the 1950's. (See G. Salamonsson,“The Ljungstrom In Situ Method for Shale-Oil Recovery,” 2^(nd) Oil Shaleand Cannel Coal Conference, v. 2, Glasgow, Scotland, Institute ofPetroleum, London, p. 260-280 (1951), the entire disclosure of which isincorporated herein by reference.)

Additional in situ methods have been proposed. These methods generallyinvolve the injection of heat and/or solvent into a subsurface oilshale. Heat may be in the form of heated methane (see U.S. Pat. No.3,241,611 to J. L. Dougan), flue gas, or superheated steam (see U.S.Pat. No. 3,400,762 to D. W. Peacock). Heat may also be in the form ofelectric resistive heating, dielectric heating, radio frequency (RF)heating (U.S. Pat. No. 4,140,180, assigned to the ITT Research Institutein Chicago, Ill.) or oxidant injection to support in situ combustion. Insome instances, artificial permeability has been created in the matrixto aid the movement of pyrolyzed fluids. Permeability generation methodsinclude mining, rubblization, hydraulic fracturing (see U.S. Pat. No.3,468,376 to M. L. Slusser and U.S. Pat. No. 3,513,914 to J. V. Vogel),explosive fracturing (see U.S. Pat. No. 1,422,204 to W. W. Hoover, etal.), heat fracturing (see U.S. Pat. No. 3,284,281 to R. W. Thomas), andsteam fracturing (see U.S. Pat. No. 2,952,450 to H. Purre).

In 1989, U.S. Pat. No. 4,886,118 issued to Shell Oil Company, the entiredisclosure of which is incorporated herein by reference. That patent,entitled “Conductively Heating a Subterranean Oil Shale to CreatePermeability and Subsequently Produce Oil,” declared that “[c]ontrary tothe implications of . . . prior teachings and beliefs . . . thepresently described conductive heating process is economically feasiblefor use even in a substantially impermeable subterranean oil shale.”(col. 6, ln. 50-54). Despite this declaration, it is noted that few, ifany, commercial in situ shale oil operations have occurred other thanLjungstrom's application. The '118 patent proposed controlling the rateof heat conduction within the rock surrounding each heat injection wellto provide a uniform heat front.

Additional history behind oil shale retorting and shale oil recovery canbe found in co-owned patent publication WO 2005/010320 entitled “Methodsof Treating a Subterranean Formation to Convert Organic Matter intoProducible Hydrocarbons,” and in patent publication WO 2005/045192entitled “Hydrocarbon Recovery from Impermeable Oil Shales.” TheBackground and technical disclosures of these two patent publicationsare incorporated herein by reference.

A need exists for improved processes for the production of shale oil. Aneed further exists for improved methods for heating a subsurfaceformation in connection with formation pyrolysis, and for the spacing ofwells in a hydrocarbon development area.

SUMMARY OF THE INVENTION

A method for spacing heater wells for an in situ conversion process isprovided. The method includes the steps of determining a direction alongwhich thermal energy will travel most efficiently through a subsurfaceformation, and completing a plurality of heater wells in the subsurfaceformation, with the heater wells being spaced farther apart in thedetermined direction than in a direction transverse to the determineddirection. Preferably, the subsurface formation comprises kerogen.

In one aspect, the step of determining a direction along which thermalenergy will travel through the subsurface formation most efficiently isperformed based upon a review of geological data pertaining to thesubsurface formation. The geological data may comprise the direction ofleast horizontal principal stress in the subsurface formation. Thedirection along which thermal energy travels through the subsurfaceformation most efficiently may be substantially perpendicular to thedirection of least horizontal principal stress. Alternatively, thedirection along which thermal energy travels through the subsurfaceformation most efficiently may be substantially parallel to thedirection of least horizontal principal stress.

The geological data may comprise the direction of bedding in thesubsurface formation. In this instance, the direction along whichthermal energy will travel through the subsurface formation mostefficiently may be substantially along the direction of bedding of thesubsurface formation.

The geological data may comprise the tilt of the subsurface formationand the relative spacing with the surface topography. In this instance,the direction along which thermal energy will travel through thesubsurface formation most efficiently may be along a direction of upwardtilt of the subsurface formation relative to either the surfacetopography or sea level.

In another aspect, the step of determining a direction along whichthermal energy will travel through the subsurface formation mostefficiently is performed based upon a review of formation temperaturegradient data from previous in situ conversion processes in other areasof the subsurface formation.

The methods may also include the steps of completing one or moreproduction wells through the subsurface formation, and then producinghydrocarbons through the production wells. The production wells may bealigned in the determined direction.

Various arrangements may be used for the heater wells. In one aspect,the heater wells are aligned in one row. In another aspect, the heaterwells are aligned in two or more rows. The pattern of heater wells maybe a line drive pattern such that two lines of heater wells are placedon opposite sides of a line of production wells. In yet another aspect,the heater wells may define sets of well patterns aligned in thedetermined direction, with each set having a production well completedthrough the surface formation. Such patterns may be 3-spot patterns,5-spot patterns, 6-spot patterns, 7-spot patterns, or other patterns.Such patterns may be sets of 3-spot and 5-spot patterns combined.

In one arrangement, a plurality of well patterns are elongated in thedetermined direction. The patterns of heater wells may comprise a firstpattern around a corresponding production well, and a second patternaround the first pattern.

In any of the above instances, the elongation ratio may be about 1.20 to2.50. In one aspect, the elongation ratio is about 2.0 to 2.5.

In another embodiment, the present disclosure offers a method forspacing heater wells for an in situ conversion process within an area ofdevelopment in which the method includes the steps of determining adirection along which thermal energy will travel most efficientlythrough a subsurface formation within the development area, andcompleting a plurality of heater wells in the subsurface formation. Inthis method, the heater wells have a density that is lower in thedetermined direction than in a direction transverse to the determineddirection. Preferably, the subsurface formation comprises kerogen. Thestep of determining a direction along which thermal energy will travelthrough the subsurface formation most efficiently may again be basedupon a review of geological data pertaining to the subsurface formation.

In one embodiment of the above methods, the step of determining adirection along which thermal energy will travel through the subsurfaceformation most efficiently is performed based upon computer modeling ofcharacteristics of the subsurface formation. Various characteristics maybe used. These include the direction of least horizontal principalstress in the subsurface formation, the direction of bedding in thesubsurface formation, or the tilt of the subsurface formation andsurface topography. Other characteristics comprise the organic carboncontent of the kerogen, hydrogen index of the subsurface formation,initial formation permeability, depth of the subsurface formation,thickness of the subsurface formation, and modified Fischer Assayanalyses. Still additional characteristics may be fluid flow and thermalgradient derived from simulations.

The present inventions also include a method for arranging heater wellsfor an in situ kerogen conversion process. In one aspect, the methodincludes providing a production well, and completing a plurality ofheater wells around the production well such that the plurality ofheater wells comprise a first layer of heater wells around theproduction well, and then a second layer of heater wells around thefirst layer. In this method, the heater wells in the second layer ofwells are arranged relative to the heater wells in the first layer ofwells so as to minimize secondary cracking of hydrocarbons convertedfrom the kerogen as the hydrocarbons flow from the second layer of wellsto the production well. The first and second layers may optionallycomprise heater wells that are elongated in a direction in which thermalenergy travels most efficiently through a targeted subsurface formation.

In this method, the heater wells are preferably completed substantiallyvertically. The plurality of heater wells and the production well arearranged such that the majority of hydrocarbons generated by heat fromeach heater well in the second layer of wells are able to migrate to theproduction well without passing near a heater well in the first layer ofwells. This may be done by offsetting the heater wells in the secondlayer of wells from the heater wells in the first layer of wellsrelative to the production well. In another aspect, the plurality ofheater wells and the production well are arranged such that the majorityof hydrocarbons generated by heat from each heater well is able tomigrate to the production well without passing through a zone ofsubstantially increasing formation temperature.

The present inventions include another method for spacing heater wellsfor an in situ conversion process. In one aspect, the method includesforming a production well through a subsurface formation, and alsocompleting a plurality of substantially vertical heater wells throughthe subsurface formation in order to pyrolyze solid hydrocarbonstherein. In this method, the heater wells are spaced around theproduction well such that a heat front emanating from each heater wellreaches the production well at substantially the same time. Preferably,the subsurface formation comprises kerogen. The heater wells may bespaced in a three-spot pattern around the production well, or otherpattern. The method may further include the step of determining adirection along which thermal energy will travel most efficientlythrough the subsurface formation.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the features of the present invention can be better understood,certain drawings, graphs and flow charts are appended hereto. It is tobe noted, however, that the drawings illustrate only selectedembodiments of the inventions and are therefore not to be consideredlimiting of scope, for the inventions may admit to other equallyeffective embodiments and applications.

FIG. 1 is a cross-sectional view of an illustrative subsurface area. Thesubsurface area includes an organic-rich rock matrix that defines asubsurface formation.

FIG. 2 is a flow chart demonstrating a general method of in situ thermalrecovery of oil and gas from an organic-rich rock formation, in oneembodiment.

FIG. 3 is cross-sectional side view of an oil shale developmentindicating ground water flow.

FIG. 4 is a process flow diagram of illustrative surface processingfacilities for a subsurface formation development.

FIG. 5 is a bar chart comparing one ton of Green River oil shale beforeand after a simulated in situ, retorting process.

FIG. 6 is an illustration of a portion of a shale oil development area,demonstrating a well spacing arrangement of the present invention, inone embodiment.

FIG. 7 is another illustration of a portion of a shale oil developmentarea, demonstrating a well spacing arrangement of the present invention,in one embodiment.

FIG. 8 is another illustration of a portion of a shale oil developmentarea, demonstrating a well spacing arrangement of the present invention,in one embodiment. Here, the heater wells are horizontally completed.

FIG. 9 presents a plan view of an illustrative heater well pattern. Theillustrative pattern uses 3-spot patterns.

FIG. 10 is a plan view of an illustrative heater well pattern, with aproduction well within each pattern. Two layers of heater wells areshown. The exemplary patterns are 5-spot patterns.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

As used herein, the term “hydrocarbon(s)” refers to organic materialwith molecular structures containing carbon bonded to hydrogen.Hydrocarbons may also include other elements, such as, but not limitedto, halogens, metallic elements, nitrogen, oxygen, and/or sulfur.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon ormixtures of hydrocarbons that are gases or liquids. For example,hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbonsthat are gases or liquids at formation conditions, at processingconditions or at ambient conditions (15° C. and 1 atm pressure).Hydrocarbon fluids may include, for example, oil, natural gas, coalbedmethane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product ofcoal, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the terms “produced fluids” and “production fluids”refer to liquids and/or gases removed from a subsurface formation,including, for example, an organic-rich rock formation. Produced fluidsmay include both hydrocarbon fluids and non-hydrocarbon fluids.Production fluids may include, but are not limited to, pyrolyzed shaleoil, synthesis gas, a pyrolysis product of coal, carbon dioxide,hydrogen sulfide and water (including steam). Produced fluids mayinclude both hydrocarbon fluids and non-hydrocarbon fluids.

As used herein, the term “condensable hydrocarbons” means thosehydrocarbons that condense at 25° C. and one atmosphere absolutepressure. Condensable hydrocarbons may include a mixture of hydrocarbonshaving carbon numbers greater than 4.

As used herein, the term “non-condensable hydrocarbons” means thosehydrocarbons that do not condense at 25° C. and one atmosphere absolutepressure. Non-condensable hydrocarbons may include hydrocarbons havingcarbon numbers less than 5.

As used herein, the term “heavy hydrocarbons” refers to hydrocarbonfluids that are highly viscous at ambient conditions (15° C. and 1 atmpressure). Heavy hydrocarbons may include highly viscous hydrocarbonfluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons mayinclude carbon and hydrogen, as well as smaller concentrations ofsulfur, oxygen, and nitrogen. Additional elements may also be present inheavy hydrocarbons in trace amounts. Heavy hydrocarbons may beclassified by API gravity. Heavy hydrocarbons generally have an APIgravity below about 20 degrees. Heavy oil, for example, generally has anAPI gravity of about 10-20 degrees, whereas tar generally has an APIgravity below about 10 degrees. The viscosity of heavy hydrocarbons isgenerally greater than about 100 centipoise at 15° C.

As used herein, the term “solid hydrocarbons” refers to any hydrocarbonmaterial that is found naturally in substantially solid form atformation conditions. Non-limiting examples include kerogen, coal,shungites, asphaltites, and natural mineral waxes.

As used herein, the term “formation hydrocarbons” refers to both heavyhydrocarbons and solid hydrocarbons that are contained in anorganic-rich rock formation. Formation hydrocarbons may be, but are notlimited to, kerogen, oil shale, coal, bitumen, tar, natural mineralwaxes, and asphaltites.

As used herein, the term “tar” refers to a viscous hydrocarbon thatgenerally has a viscosity greater than about 10,000 centipoise at 15° C.The specific gravity of tar generally is greater than 1.000. Tar mayhave an API gravity less than 10 degrees. “Tar sands” refers to aformation that has tar in it.

As used herein, the term “kerogen” refers to a solid, insolublehydrocarbon that principally contains carbon, hydrogen, nitrogen,oxygen, and sulfur. Oil shale contains kerogen.

As used herein, the term “bitumen” refers to a non-crystalline solid orviscous hydrocarbon material that is substantially soluble in carbondisulfide.

As used herein, the term “oil” refers to a hydrocarbon fluid containinga mixture of condensable hydrocarbons.

As used herein, the term “subsurface” refers to geologic strataoccurring below the earth's surface.

As used herein, the term “hydrocarbon-rich formation” refers to anyformation that contains more than trace amounts of hydrocarbons. Forexample, a hydrocarbon-rich formation may include portions that containhydrocarbons at a level of greater than 5 volume percent. Thehydrocarbons located in a hydrocarbon-rich formation may include, forexample, oil, natural gas, heavy hydrocarbons, and solid hydrocarbons.

As used herein, the term “organic-rich rock” refers to any rock matrixholding solid hydrocarbons and/or heavy hydrocarbons. Rock matrices mayinclude, but are not limited to, sedimentary rocks, shales, siltstones,sands, silicilytes, carbonates, and diatomites.

As used herein, the term “formation” refers to any finite subsurfaceregion. The formation may contain one or more hydrocarbon-containinglayers, one or more non-hydrocarbon containing layers, an overburden,and/or an underburden of any subsurface geologic formation. An“overburden” and/or an “underburden” is geological material above orbelow the formation of interest. An overburden or underburden mayinclude one or more different types of substantially impermeablematerials. For example, overburden and/or underburden may include rock,shale, mudstone, or wet/tight carbonate (i.e., an impermeable carbonatewithout hydrocarbons). An overburden and/or an underburden may include ahydrocarbon-containing layer that is relatively impermeable. In somecases, the overburden and/or underburden may be permeable.

As used herein, the term “organic-rich rock formation” refers to anyformation containing organic-rich rock. Organic-rich rock formationsinclude, for example, oil shale formations, coal formations, and tarsands formations.

As used herein, the term “pyrolysis” refers to the breaking of chemicalbonds through the application of heat. For example, pyrolysis mayinclude transforming a compound into one or more other substances byheat alone or by heat in combination with an oxidant. Pyrolysis mayinclude modifying the nature of the compound by addition of hydrogenatoms which may be obtained from molecular hydrogen, water, carbondioxide, or carbon monoxide. Heat may be transferred to a section of theformation to cause pyrolysis.

As used herein, the term “water-soluble minerals” refers to mineralsthat are soluble in water. Water-soluble minerals include, for example,nahcolite (sodium bicarbonate), soda ash (sodium carbonate), dawsonite(NaAl(CO₃)(OH)₂), or combinations thereof. Substantial solubility mayrequire heated water and/or a non-neutral pH solution.

As used herein, the term “formation water-soluble minerals” refers towater-soluble minerals that are found naturally in a formation.

As used herein, the term “migratory contaminant species” refers tospecies that are both soluble or moveable in water or an aqueous fluid,and are considered to be potentially harmful or of concern to humanhealth or the environment. Migratory contaminant species may includeinorganic and organic contaminants. Organic contaminants may includesaturated hydrocarbons, aromatic hydrocarbons, and oxygenatedhydrocarbons. Inorganic contaminants may include metal contaminants, andionic contaminants of various types that may significantly alter pH orthe formation fluid chemistry. Aromatic hydrocarbons may include, forexample, benzene, toluene, xylene, ethylbenzene, and tri-methylbenzene,and various types of polyaromatic hydrocarbons such as anthracenes,naphthalenes, chrysenes and pyrenes. Oxygenated hydrocarbons mayinclude, for example, alcohols, ketones, phenols, and organic acids suchas carboxylic acid. Metal contaminants may include, for example,arsenic, boron, chromium, cobalt, molybdenum, mercury, selenium, lead,vanadium, nickel or zinc. Ionic contaminants include, for example,sulfides, sulfates, chlorides, fluorides, ammonia, nitrates, calcium,iron, magnesium, potassium, lithium, boron, and strontium.

As used herein, the term “cracking” refers to a process involvingdecomposition and molecular recombination of organic compounds toproduce a greater number of molecules than were initially present. Incracking, a series of reactions take place accompanied by a transfer ofhydrogen atoms between molecules. For example, naphtha may undergo athermal cracking reaction to form ethene and H₂ among other molecules.

As used herein, the term “sequestration” refers to the storing of afluid that is a by-product of a process rather than discharging thefluid to the atmosphere or open environment.

As used herein, the term “subsidence” refers to a downward movement of asurface relative to an initial elevation of the surface.

As used herein, the term “thickness” of a layer refers to the distancebetween the upper and lower boundaries of a cross section of a layer,wherein the distance is measured normal to the average tilt of the crosssection.

As used herein, the term “thermal fracture” refers to fractures createdin a formation caused directly or indirectly by expansion or contractionof a portion of the formation and/or fluids within the formation, whichin turn is caused by increasing/decreasing the temperature of theformation and/or fluids within the formation, and/or byincreasing/decreasing a pressure of fluids within the formation due toheating. Thermal fractures may propagate into or form in neighboringregions significantly cooler than the heated zone.

As used herein, the term “hydraulic fracture” refers to a fracture atleast partially propagated into a formation, wherein the fracture iscreated through injection of pressurized fluids into the formation. Thefracture may be artificially held open by injection of a proppantmaterial. Hydraulic fractures may be substantially horizontal inorientation, substantially vertical in orientation, or oriented alongany other plane.

As used herein, the term “wellbore” refers to a hole in the subsurfacemade by drilling or insertion of a conduit into the subsurface. Awellbore may have a substantially circular cross section, or othercross-sectional shapes (e.g., circles, ovals, squares, rectangles,triangles, slits, or other regular or irregular shapes). As used herein,the term “well”, when referring to an opening in the formation, may beused interchangeably with the term “wellbore.”

Description of Specific Embodiments

The inventions are described herein in connection with certain specificembodiments. However, to the extent that the following detaileddescription is specific to a particular embodiment or a particular use,such is intended to be illustrative only and is not to be construed aslimiting the scope of the inventions.

As discussed herein, some embodiments of the inventions include or haveapplication related to an in situ method of recovering naturalresources. The natural resources may be recovered from an organic-richrock formation, including, for example, an oil shale formation. Theorganic-rich rock formation may include formation hydrocarbons,including, for example, kerogen, coal, and heavy hydrocarbons. In someembodiments of the inventions the natural resources may includehydrocarbon fluids, including, for example, products of the pyrolysis offormation hydrocarbons such as oil shale. In some embodiments of theinventions the natural resources may also include water-solubleminerals, including, for example, nahcolite (sodium bicarbonate, orNaHCO₃), soda ash (sodium carbonate, or Na₂CO₃) and dawsonite(NaAl(CO₃)(OH)₂).

FIG. 1 presents a perspective view of an illustrative oil shaledevelopment area 10. A surface 12 of the development area 10 isindicated. Below the surface is an organic-rich rock formation 16. Theillustrative subsurface formation 16 contains formation hydrocarbons(such as, for example, kerogen) and possibly valuable water-solubleminerals (such as, for example, nahcolite). It is understood that therepresentative formation 16 may be any organic-rich rock formation,including a rock matrix containing coal or tar sands, for example. Inaddition, the rock matrix making up the formation 16 may be permeable,semi-permeable or non-permeable. The present inventions are particularlyadvantageous in oil shale development areas initially having verylimited or effectively no fluid permeability.

In order to access formation 16 and recover natural resources therefrom,a plurality of wellbores is formed. Wellbores are shown at 14 in FIG. 1.The representative wellbores 14 are essentially vertical in orientationrelative to the surface 12. However, it is understood that some or allof the wellbores 14 could deviate into an obtuse or even horizontalorientation. In the arrangement of FIG. 1, each of the wellbores 14 iscompleted in the oil shale formation 16. The completions may be eitheropen or cased hole. The well completions may also include propped orunpropped hydraulic fractures emanating therefrom.

In the view of FIG. 1, only seven wellbores 14 are shown. However, it isunderstood that in an oil shale development project, numerous additionalwellbores 14 will most likely be drilled. The wellbores 14 may belocated in relatively close proximity, being from 10 feet to up to 300feet in separation. In some embodiments, a well spacing of 15 to 25 feetis provided. Typically, the wellbores 14 are also completed at shallowdepths, being from 200 to 5,000 feet at total depth. In some embodimentsthe oil shale formation targeted for in situ retorting is at a depthgreater than 200 feet below the surface or alternatively 400 feet belowthe surface. Alternatively, conversion and production of an oil shaleformation occur at depths between 500 and 2,500 feet.

The wellbores 14 will be selected for certain functions and may bedesignated as heat injection wells, water injection wells, oilproduction wells and/or water-soluble mineral solution production wells.In one aspect, the wellbores 14 are dimensioned to serve two, three, orall four of these purposes. Suitable tools and equipment may besequentially run into and removed from the wellbores 14 to serve thevarious purposes.

A fluid processing facility 17 is also shown schematically. The fluidprocessing facility 17 is equipped to receive fluids produced from theorganic-rich rock formation 16 through one or more pipelines or flowlines 18. The fluid processing facility 17 may include equipmentsuitable for receiving and separating oil, gas and water produced fromthe heated formation. The fluid processing facility 17 may furtherinclude equipment for separating out dissolved water-soluble mineralsand/or migratory contaminant species including, for example, dissolvedorganic contaminants, metal contaminants, or ionic contaminants in theproduced water recovered from the organic-rich rock formation 16. Thecontaminants may include, for example, aromatic hydrocarbons such asbenzene, toluene, xylene, and tri-methylbenzene. The contaminants mayalso include polyaromatic hydrocarbons such as anthracene, naphthalene,chrysene and pyrene. Metal contaminants may include species containingarsenic, boron, chromium, mercury, selenium, lead, vanadium, nickel,cobalt, molybdenum, or zinc. Ionic contaminant species may include, forexample, sulfates, chlorides, fluorides, lithium, potassium, aluminum,ammonia, and nitrates.

In order to recover oil, gas, and sodium (or other) water-solubleminerals, a series of steps may be undertaken. FIG. 2 presents a flowchart demonstrating a method of in situ thermal recovery of oil and gasfrom an organic-rich rock formation 100, in one embodiment. It isunderstood that the order of some of the steps from FIG. 2 may bechanged, and that the sequence of steps is merely for illustration.

First, the oil shale (or other organic-rich rock) formation 16 isidentified within the development area 10. This step is shown in box110. Optionally, the oil shale formation may contain nahcolite or othersodium minerals. The targeted development area within the oil shaleformation may be identified by measuring or modeling the depth,thickness and organic richness of the oil shale as well as evaluatingthe position of the organic-rich rock formation relative to other rocktypes, structural features (e.g. faults, anticlines or synclines), orhydrogeological units (i.e. aquifers). This is accomplished by creatingand interpreting maps and/or models of depth, thickness, organicrichness and other data from available tests and sources. This mayinvolve performing geological surface surveys, studying outcrops,performing seismic surveys, and/or drilling boreholes to obtain coresamples from subsurface rock. Rock samples may be analyzed to assesskerogen content and hydrocarbon fluid-generating capability.

The kerogen content of the organic-rich rock formation may beascertained from outcrop or core samples using a variety of data. Suchdata may include organic carbon content, hydrogen index, and modifiedFischer assay analyses. Subsurface permeability may also be assessed viarock samples, outcrops, or studies of ground water flow. Furthermore theconnectivity of the development area to ground water sources may beassessed.

Next, a plurality of wellbores 14 is formed across the targeteddevelopment area 10. This step is shown schematically in box 115. Thepurposes of the wellbores 14 are set forth above and need not berepeated. However, it is noted that for purposes of the wellboreformation step of box 115, only a portion of the wells need be completedinitially. For instance, at the beginning of the project heat injectionwells are needed, while a majority of the hydrocarbon production wellsare not yet needed. Production wells may be brought in once conversionbegins, such as after 4 to 12 months of heating.

It is understood that petroleum engineers will develop a strategy forthe best depth and arrangement for the wellbores 14, depending uponanticipated reservoir characteristics, economic constraints, and workscheduling constraints. In addition, engineering staff will determinewhat wellbores 14 shall be used for initial formation 16 heating. Thisselection step is represented by box 120.

Concerning heat injection wells, there are various methods for applyingheat to the organic-rich rock formation 16. The present methods are notlimited to the heating technique employed unless specifically so statedin the claims. The heating step is represented generally by box 130.Preferably, for in situ processes the heating of a production zone takesplace over a period of months, or even four or more years.

The formation 16 is heated to a temperature sufficient to pyrolyze atleast a portion of the oil shale in order to convert the kerogen tohydrocarbon fluids. The bulk of the target zone of the formation may beheated to between 270° C. to 800° C. Alternatively, the targeted volumeof the organic-rich formation is heated to at least 350° C. to createproduction fluids. The conversion step is represented in FIG. 2 by box135. The resulting liquids and hydrocarbon gases may be refined intoproducts which resemble common commercial petroleum products. Suchliquid products include transportation fuels such as diesel, jet fueland naptha. Generated gases include light alkanes, light alkenes, H₂,CO₂, CO, and NH₃.

Conversion of the oil shale will create permeability in the oil shalesection in rocks that were originally impermeable. Preferably, theheating and conversion processes of boxes 130 and 135, occur over alengthy period of time. In one aspect, the heating period is from threemonths to four or more years. Also as an optional part of box 135, theformation 16 may be heated to a temperature sufficient to convert atleast a portion of nahcolite, if present, to soda ash. Heat applied tomature the oil shale and recover oil and gas will also convert nahcoliteto sodium carbonate (soda ash), a related sodium mineral. The process ofconverting nahcolite (sodium bicarbonate) to soda ash (sodium carbonate)is described herein.

In connection with the heating step 130, the rock formation 16 mayoptionally be fractured to aid heat transfer or later hydrocarbon fluidproduction. The optional fracturing step is shown in box 125. Fracturingmay be accomplished by creating thermal fractures within the formationthrough application of heat. By heating the organic-rich rock andtransforming the kerogen to oil and gas, the permeability of portions ofthe formation are increased via thermal fracture formation andsubsequent production of a portion of the hydrocarbon fluids generatedfrom the kerogen. Alternatively, a process known as hydraulic fracturingmay be used. Hydraulic fracturing is a process known in the art of oiland gas recovery where a fracture fluid is pressurized within thewellbore above the fracture pressure of the formation, thus developingfracture planes within the formation to relieve the pressure generatedwithin the wellbore. Hydraulic fractures may be used to createadditional permeability in portions of the formation and/or be used toprovide a planar source for heating.

As part of the hydrocarbon fluid production process 100, certain wells14 may be designated as oil and gas production wells. This step isdepicted by box 140. Oil and gas production might not be initiated untilit is determined that the kerogen has been sufficiently retorted toallow maximum recovery of oil and gas from the formation 16. In someinstances, dedicated production wells are not drilled until after heatinjection wells (box 130) have been in operation for a period of severalweeks or months. Thus, box 140 may include the formation of additionalwellbores 14. In other instances, selected heater wells are converted toproduction wells.

After certain wellbores 14 have been designated as oil and gasproduction wells, oil and/or gas is produced from the wellbores 14. Theoil and/or gas production process is shown at box 145. At this stage(box 145), any water-soluble minerals, such as nahcolite and convertedsoda ash may remain substantially trapped in the rock formation 16 asfinely disseminated crystals or nodules within the oil shale beds, andare not produced. However, some nahcolite and/or soda ash may bedissolved in the water created during heat conversion (box 135) withinthe formation.

Box 150 presents an optional next step in the oil and gas recoverymethod 100. Here, certain wellbores 14 are designated as water oraqueous fluid injection wells. Aqueous fluids are solutions of waterwith other species. The water may constitute “brine,” and may includedissolved inorganic salts of chloride, sulfates and carbonates of GroupI and II elements of The Periodic Table of Elements. Organic salts canalso be present in the aqueous fluid. The water may alternatively befresh water containing other species. The other species may be presentto alter the pH. Alternatively, the other species may reflect theavailability of brackish water not saturated in the species wished to beleached from the subsurface. Preferably, the water injection wells areselected from some or all of the wellbores used for heat injection orfor oil and/or gas production. However, the scope of the step of box 150may include the drilling of yet additional wellbores 14 for use asdedicated water injection wells. In this respect, it may be desirable tocomplete water injection wells along a periphery of the development area10 in order to create a boundary of high pressure.

Next, optionally water or an aqueous fluid is injected through the waterinjection wells and into the oil shale formation 16. This step is shownat box 155. The water may be in the form of steam or pressurized hotwater. Alternatively the injected water may be cool and becomes heatedas it contacts the previously heated formation. The injection processmay further induce fracturing. This process may create fingered cavernsand brecciated zones in the nahcolite-bearing intervals some distance,for example up to 200 feet out, from the water injection wellbores. Inone aspect, a gas cap, such as nitrogen, may be maintained at the top ofeach “cavern” to prevent vertical growth.

Along with the designation of certain wellbores 14 as water injectionwells, the design engineers may also designate certain wellbores 14 aswater or water-soluble mineral solution production wells. This step isshown in box 160. These wells may be the same as wells used topreviously produce hydrocarbons or inject heat. These recovery wells maybe used to produce an aqueous solution of dissolved water-solubleminerals and other species, including, for example, migratorycontaminant species. For example, the solution may be one primarily ofdissolved soda ash. This step is shown in box 165. Alternatively, singlewellbores may be used to both inject water and then to recover a sodiummineral solution. Thus, box 165 includes the option of using the samewellbores 14 for both water injection and solution production (box 165).

Temporary control of the migration of the migratory contaminant species,especially during the pyrolysis process, can be obtained via placementof the injection and production wells 14 such that fluid flow out of theheated zone is minimized. Typically, this involves placing injectionwells at the periphery of the heated zone so as to cause pressuregradients which prevent flow inside the heated zone from leaving thezone.

FIG. 3 is a cross-sectional view of an illustrative oil shale formationthat is within or connected to ground water aquifers and a formationleaching operation. Four separate oil shale formation zones are depicted(23, 24, 25 and 26) within the oil shale formation. The water aquifersare below the ground surface 27, and are categorized as an upper aquifer20 and a lower aquifer 22. Intermediate the upper and lower aquifers isan aquitard 21. It can be seen that certain zones of the formation areboth aquifers or aquitards and oil shale zones. A plurality of wells(28, 29, 30 and 31) is shown traversing vertically downward through theaquifers. One of the wells is serving as a water injection well 31,while another is serving as a water production well 30. In this way,water is circulated 32 through at least the lower aquifer 22.

FIG. 3 shows diagrammatically the water circulation 32 through an oilshale zone 33 that was heated, that resides within or is connected to anaquifer 22, and from which hydrocarbon fluids were previously recovered.Introduction of water via the water injection well 31 forces water intothe previously heated oil shale zone 33 so that water-soluble mineralsand migratory contaminants species are swept to the water productionwell 30. The water may then processed in a facility 34 wherein thewater-soluble minerals (e.g. nahcolite or soda ash) and the migratorycontaminants may be substantially removed from the water stream. Wateris then reinjected into the oil shale zone 33 and the formation leachingis repeated. This leaching with water is intended to continue untillevels of migratory contaminant species are at environmentallyacceptable levels within the previously heated oil shale zone 33. Thismay require 1 cycle, 2 cycles, 5 cycles 10 cycles or more cycles offormation leaching, where a single cycle indicates injection andproduction of approximately one pore volume of water.

It is understood that there may be numerous water injection and waterproduction wells in an actual oil shale development. Moreover, thesystem may include monitoring wells (28 and 29) which can be utilizedduring the oil shale heating phase, the shale oil production phase, theleaching phase, or during any combination of these phases to monitor formigratory contaminant species and/or water-soluble minerals.

In some fields, formation hydrocarbons, such as oil shale, may exist inmore than one subsurface formation. In some instances, the organic-richrock formations may be separated by rock layers that arehydrocarbon-free or that otherwise have little or no commercial value.Therefore, it may be desirable for the operator of a field underhydrocarbon development to undertake an analysis as to which of thesubsurface, organic-rich rock formations to target or in which orderthey should be developed.

The organic-rich rock formation may be selected for development based onvarious factors. One such factor is the thickness of the hydrocarboncontaining layer within the formation. Greater pay zone thickness mayindicate a greater potential volumetric production of hydrocarbonfluids. Each of the hydrocarbon containing layers may have a thicknessthat varies depending on, for example, conditions under which theformation hydrocarbon containing layer was formed. Therefore, anorganic-rich rock formation will typically be selected for treatment ifthat formation includes at least one formation hydrocarbon-containinglayer having a thickness sufficient for economical production ofproduced fluids.

An organic-rich rock formation may also be chosen if the thickness ofseveral layers that are closely spaced together is sufficient foreconomical production of produced fluids. For example, an in situconversion process for formation hydrocarbons may include selecting andtreating a layer within an organic-rich rock formation having athickness of greater than about 5 meters, 10 meters, 50 m, or even 100meters. In this manner, heat losses (as a fraction of total injectedheat) to layers formed above and below an organic-rich rock formationmay be less than such heat losses from a thin layer of formationhydrocarbons. A process as described herein, however, may also includeselecting and treating layers that may include layers substantially freeof formation hydrocarbons or thin layers of formation hydrocarbons.

The richness of one or more organic-rich rock formations may also beconsidered. Richness may depend on many factors including the conditionsunder which the formation hydrocarbon containing layer was formed, anamount of formation hydrocarbons in the layer, and/or a composition offormation hydrocarbons in the layer. A thin and rich formationhydrocarbon layer may be able to produce significantly more valuablehydrocarbons than a much thicker, less rich formation hydrocarbon layer.Of course, producing hydrocarbons from a formation that is both thickand rich is desirable.

The kerogen content of an organic-rich rock formation may be ascertainedfrom outcrop or core samples using a variety of data. Such data mayinclude organic carbon content, hydrogen index, and modified Fischerassay analyses. The Fischer Assay is a standard method which involvesheating a sample of a formation hydrocarbon containing layer toapproximately 500° C. in one hour, collecting fluids produced from theheated sample, and quantifying the amount of fluids produced.

Subsurface formation permeability may also be assessed via rock samples,outcrops, or studies of ground water flow. Furthermore the connectivityof the development area to ground water sources may be assessed. Thus,an organic-rich rock formation may be chosen for development based onthe permeability or porosity of the formation matrix even if thethickness of the formation is relatively thin.

Other factors known to petroleum engineers may be taken intoconsideration when selecting a formation for development. Such factorsinclude depth of the perceived pay zone, stratigraphic proximity offresh ground water to kerogen-containing zones, continuity of thickness,and other factors. For instance, the assessed fluid production contentwithin a formation will also effect eventual volumetric production.

In producing hydrocarbon fluids from an oil shale field, it may bedesirable to control the migration of pyrolyzed fluids. In someinstances, this includes the use of injection wells, particularly aroundthe periphery of the field. Such wells may inject water, steam, CO₂,heated methane, or other fluids to drive cracked kerogen fluids inwardlytowards production wells. In some embodiments, physical barriers may beplaced around the area of the organic-rich rock formation underdevelopment. One example of a physical barrier involves the creation offreeze walls. Freeze walls are formed by circulating refrigerant throughperipheral wells to substantially reduce the temperature of the rockformation. This, in turn, prevents the pyrolyzation of kerogen presentat the periphery of the field and the outward migration of oil and gas.Freeze walls will also cause native water in the formation along theperiphery to freeze.

The use of subsurface freezing to stabilize poorly consolidated soils orto provide a barrier to fluid flow is known in the art. ShellExploration and Production Company has discussed the use of freeze wallsfor oil shale production in several patents, including U.S. Pat. No.6,880,633 and U.S. Pat. No. 7,032,660. Shell's '660 patent usessubsurface freezing to protect against groundwater flow and groundwatercontamination during in situ shale oil production. Additional patentsthat disclose the use of so-called freeze walls are U.S. Pat. No.3,528,252, U.S. Pat. No. 3,943,722, U.S. Pat. No. 3,729,965, U.S. Pat.No. 4,358,222, U.S. Pat. No. 4,607,488, and WO Pat. No. 98996480.

Another example of a physical barrier that may be used to limit fluidflow into or out of an oil shale field is the creation of grout walls.Grout walls are formed by injecting cement into the formation to fillpermeable pathways. In the context of an oil shale field, cement wouldbe injected along the periphery of the field. This prevents the movementof pyrolyzed fluids out of the field under development, and the movementof water from adjacent aquifers into the field.

As noted above, several different types of wells may be used in thedevelopment of an oil shale field. These may include primarily heaterwells and hydrocarbon production wells. However, the wells may alsoinclude, for example, injection wells and solution production wells.

The heating of the organic-rich rock formation is accomplished throughthe use of the heater wells. The heater wells provide a means forheating a portion of a subsurface formation and may include, forexample, electrical resistance heating elements, hot fluid circulation,or downhole combustion. The heating elements may be within the wellbore,or may extend away from the wellbore downhole.

In some instances, horizontally completed heater wells may be employed.The Assignee has disclosed a technique of using horizontally completedheater wells in international patent publication WO 2005/010320, citedabove. This patent application teaches the use of electricallyconductive fractures emanating from the horizontal wellbores to heat anoil shale formation. A heating element is constructed by formingmultiple horizontal wellbores and then hydraulically fracturing the oilshale formation around the wellbores. The fractures are filled with anelectrically conductive material which forms the heating element.Calcined petroleum coke is an exemplary suitable conductant material.Preferably, the fractures are created in a vertical orientation alonglongitudinal, horizontal planes formed by the horizontally completedwellbores. Electricity may be conducted through the conductive fracturesfrom the heel to the toe of each well. To avoid a short circuit, thehorizontal portion of the wellbores adjacent to current flow may beconstructed from non-conducting material. The electrical circuit may becompleted by an additional horizontal well that intersects one or moreof the vertical fractures near the toe to supply the opposite electricalpolarity. Alternatively, vertical wells having the opposite polarity maybe drilled to intersect the conductive granular material. Lateral heatconduction transfers heat to the oil shale adjacent to the verticalfractures, converting the kerogen to oil and gas.

In order to create fractures in this arrangement, the horizontalwellbores may be oriented perpendicular to the least principle stresswithin the formation. In the Piceance Basin, this direction is believedto be roughly WNW-ESE.

In an alternate arrangement for heater wells, a plurality of verticalheater wells may be formed, with vertical fractures formed therefrom. Inthis design, a current may be conducted vertically from the upper tolower portions of the fracture. Horizontal wells may then be drilled tointercept multiple fractures, completing the circuits of several heaterwells.

Heater wells may also operate to circulate a heated fluid such asmethane gas or naptha through the formation. The heated fluid iscirculated through fractures connecting adjacent wellbores of the heaterwells. In one aspect, the wellbores are horizontally completed.

The production of hydrocarbon fluids from the heated formation may beaccomplished through the use of the production wells. These are wellsthat are completed or, perhaps, converted for the production of fluids.Pyrolyzed fluids are transported from the formation, into wellbores forthe production wells, and upward to the surface. The pyrolyzed fluidsare then gathered and processed.

The injection of an aqueous fluid may be accomplished through the use ofinjection wells. The injection wells may be used to flood theorganic-rich rock formation in order to drive other fluids, or may beused to treat the formation in order to change its characteristics. Theaqueous solution may be reclaimed or otherwise produced to the surfacethrough the use of the solution production wells.

It is desirable to reduce the number of wells in order to reduce projectcosts. One method is to use a single well for sequential purposes.Stated another way, wells initially completed for one purpose may beused for another purpose, either at the same time or later after beingreworked. This serves to lower project costs and/or decrease the timerequired to perform certain tasks. For instance, a single wellbore mightbe completed as a heater well and later converted to a production well.In addition, one or more monitoring wells may be disposed at selectedpoints in the field, with the monitoring wells being configured with oneor more devices that measure a temperature, a pressure, and/or aproperty of a fluid in the wellbore. In some instances, a heater wellmay also serve as a monitoring well, or may otherwise be instrumented.

In another example, one or more of the production wells may later beused as injection wells for later injecting water into the organic-richrock formation. Alternatively, one or more of the production wells maylater be used as solution production wells for producing an aqueoussolution from the organic-rich rock formation. In other aspects,production wells (and, in some circumstances, heater wells) mayinitially be used as dewatering wells. This might occur before heatingis begun and/or when heating is initially started. In addition, in somecircumstances dewatering wells can later be used as production wells or,in some circumstances, heater wells. As such, the dewatering wells maybe placed and/or designed so that such wells can be later used asproduction wells and/or heater wells.

In other examples, the heater wells may be placed and/or designed sothat they can later be used as dewatering wells, either before heatingor after hydrocarbon production. Also, the production wells may beplaced and/or designed so that such wells can later be used asdewatering wells and/or heater wells. Similarly, injection wells may bewells that initially were used for other purposes (e.g., heating,production, dewatering, monitoring, etc.), and may later be used forother purposes. Similarly, monitoring wells may be wells that initiallywere used for other purposes (e.g., heating, production, dewatering,injection, etc.). Such monitoring wells may later be used for otherpurposes such as water production or formation sweeping.

It is desirable to arrange the various wells for an oil shale field in apre-planned pattern. For instance, heater wells may be arranged in avariety of patterns including, but not limited to triangles, squares,hexagons, and other polygons. The pattern may include a regular polygonto promote uniform heating through at least the portion of the formationin which the heater wells are placed. Typically, a polygonal patternwill provide a production well proximate to the center of the heaterwell pattern.

In some instances, the use of a polygonal pattern of heater wells mayreduce the number of heater wells actually needed. U.S. Pat. No.6,913,078, for example, teaches the use of regular patterns of heaterwells equidistantly spaced from a production well. The patterns may formequilateral triangular arrays, equilateral hexagonal arrays, or otherarray patterns. The arrays of heater wells may be disposed such that adistance between each heater well is less than about 70 feet (21 m). The'078 patent issued to Shell Oil Company, and is hereby incorporated byreference.

The well pattern may also be a line drive pattern. A line drive patterngenerally includes a first linear array of heater wells, a second lineararray of heater wells, and a production well or a line of productionwells between the first and second linear arrays of heater wells.However, it is noted that line drive patterns may also be thought of asrepeating rectangular patterns of wells. Therefore, such arrays may alsobe categorized as polygonal patterns.

A linear array of heater wells may be disposed such that a distancebetween each heater well may be less than about 100 feet, or 50 feet, or30 feet. A portion of the formation may be heated with heater wellsdisposed substantially parallel to a boundary of the hydrocarbonformation. Regardless of the arrangement of or distance between theheater wells, in certain embodiments, a ratio of heater wells toproduction wells disposed within a organic-rich rock formation may begreater than about 5, 8, 10, 20, or more.

In accordance with the present disclosure, another method to reduce thenumber of heater wells is to use well patterns that are elongated in aparticular direction, particularly in the direction of most efficientthermal transfer within the subsurface formation. The determination ofmost efficient thermal transfer direction and, thus, the elongationdirection, may be based upon a variety of factors. These include but arenot limited to geological data regarding the formation. For instance,heat convection may be more efficient in the direction perpendicular tothe least horizontal principal stress on the formation. In someinstances, heat convection may be more efficient in the directionparallel to least horizontal principal stress. In either instance,heater well spacing may be elongated in the direction of most efficientheat convection or other energy transfer mechanism. Elongation may be bya factor of 1.2, 1.5, 2.0, or greater.

FIG. 6 is an illustration of a portion of a hydrocarbon development area600 demonstrating a well spacing arrangement of the present invention,in one embodiment. The development area 600 represents a surface 602,and a formation 610 below the surface 602. The subsurface formation 610is an organic rich rock formation, such as oil shale. The developmentarea 600 is for the purpose of developing hydrocarbons from thesubsurface oil shale formation 610.

The formation 610 of FIG. 6 has a thickness “t”. In some instances, thethickness “t” will vary. It can be seen in the formation 610 that at onepoint the thickness is at t₁. At another point in the formation 610, thethickness increases to t₂. For economic reasons, it is preferred thatthe minimum thickness t₁ be at least 50 feet. However, the presentinventions are not limited by the thicknesses of the formation 610.

The formation 610 also has a depth “d”. In some instances, the depth “d”will vary. At one point, the distance from the surface 602 to the top ofthe formation 610 is at d₁. At another point in the formation 610, thedistance from the surface 602 to the top of the formation 610 is at d₂.In some embodiments, the oil shale formation 610 targeted for in situretorting is at a depth greater than 200 feet below the surface. Inalternative embodiments, the oil shale formation 610 targeted for insitu retorting is at a depth greater than 500, 1000, or 1500 feet belowthe surface 602, but typically no deeper than 5,000 feet. In alternativeembodiments, the oil shale formation 610 targeted for in situ retortingis at a depth between 500 and 4,000 feet, alternatively between 600 and3,500 feet, or 700 and 3,000 feet below the surface 602.

The formation 610 of FIG. 6 has a direction in which thermal energytravels most efficiently. Arrow 604 demonstrates the illustrateddirection of most efficient travel for thermal energy. Arrow 606demonstrates a direction essentially normal to direction 604. Thedirection in which thermal energy travels most efficiently is typicallya function of geological features of the targeted formation 610.

The formation 610 has a very limited permeability initially, e.g., lessthan 5 millidarcies. In order to develop the oil shale formation 610, itis necessary to pyrolyze the solid hydrocarbons in the formation 610.This is done by heating the formation 610 above a pyrolysis temperaturefor an extended period of time. In order to heat the formation 610 andproduce hydrocarbons, a plurality of heater wells 630 are provided. Inthe illustrative development area 600, the heater wells 630 are arrangedin a plurality of rows, or linear arrays. Each heater well 630 has awellbore 632 extending down to and completed in the formation 610. Eachwellbore 632 in the arrangement of FIG. 6 is substantially vertical.

Preferably, the heater wells 630 are designed to provide resistive heatto the formation 610 at a selected temperature. However, other heatingmethods such as the use of downhole combustible burners may be used. Inone aspect, the heated and pyrolyzed oil shale formation 610 will havean average permeability of greater than 10 millidarcies after heating.The heater wells 630 may be located in relatively close proximity, beingfrom 10 feet to up to 300 feet in separation. Alternatively, thewellbores may be spaced from 30 to 200 feet or from 50 to 100 feet.

It is noted that the heater wells 630 are farther apart in the directionof arrow 604, that is, the direction of most efficient thermal energytransfer, as compared to the direction of arrow 606. This means that theheater wells 630 are elongated along the direction in which thermalenergy will travel most efficiently through the subsurface formation610. In one example, the elongation ratio may be about 1.2 to about 2.5.Alternatively, the elongation ratio is about 2.0 to 2.5.

For a repeating pattern of wells where the smallest repeating patterncan be delimited by an isosceles triangle, a parallelogram, or a hexagonwith parallel opposite sides, the elongation ratio is the ratio of thelength of a longest side to the length of a shortest side. For arepeating pattern of wells where a repeating pattern can be delimited byan isosceles triangle, a parallelogram, or a hexagon with parallelopposite sides where all wells are positioned on the sides of therepeating polygon, the elongation ratio is the ratio of the length of alongest side to the length of a shortest side multiplied by the ratio ofthe number wells along a shortest side to the number of wells along alongest side.

Interspersed between the lines of heater wells 630 are production wells640. Each production well 640 has a wellbore 642 extending down to andcompleted in the formation 610. Each production wellbore 642 in thearrangement of FIG. 6 is also substantially vertical. Pyrolyzedhydrocarbon fluids migrate in the formation 610 to the wellbores 642 ofthe production wells 640.

As noted, a variety of factors may affect or cause thermal energy to betransferred more efficiently in one direction than in another. One suchfactor is stresses acting on the formation 610, primarily leasthorizontal principal stress. These stresses may in turn affect thepreferred direction of thermal fracturing upon heating. Thermalfractures can enhance convective heat transfer. The relationship betweenmost efficient thermal transfer direction and the direction of leasthorizontal principal stress may be based upon experimental studies ofthe formation. Such may also be based upon prior empirical experiencewith the formation or similar formations. The relationship may also beestablished through computer modeling or simulation including, but notlimited to, fluid flow simulation or thermal gradient simulation.Various characteristics of the formation 610 may be taken into accountin studies or simulations. Such characteristics may include the organiccarbon content of the kerogen in the formation 610, the hydrogen indexof the formation 610, the initial permeability of the formation 610, thedepth of the formation 610, the thickness of the formation 610, theheterogeneity of rock in the formation 610, and modified Fischer Assayanalyses.

In connection with the permeability characteristic, it is noted that theprocess of heating an oil shale formation also changes the permeabilityof the formation. By heating the oil shale and transforming the kerogento oil and gas, the permeability is increased through the gradualconversion of kerogen to fluids. Where the conversion rate is faster,i.e., more efficient, in a first direction, then the heater well spacingmay be elongated in that first direction relative to a second transversedirection so that the conversion rate within the organic-rich rock issubstantially the same.

The heater well spacing 630 may also be described in terms ofdirectional density. Directional density may be functionally defined asthe reciprocal distance between a specified well and the nearestneighboring well whose connecting line segment falls within +30° and−30° of the specified direction. In the arrangement 600 of FIG. 6, theheater well spacing 630 has a density that is lower in the determineddirection 604 than in the direction 606 normal or transverse to thedetermined direction 604. This is also demonstrated in the arrangement700 of FIG. 7 and in the arrangement 800 of FIG. 8, discussed below.

The heating of a portion of a formation such as formation 610 may alsocause fracture formation due to temperature differentials with adjacentunheated rock. Thermal fracturing can occur both in the immediate regionundergoing heating, and in cooler neighboring regions. The thermalfracturing in the neighboring regions is due to propagation of fracturesand tension stresses developed due to rock expansion in the hotterzones. Thermal fracture formation may also be caused by chemicalexpansion of the transforming kerogen into oil and gas. Thermalfractures increase permeability and aid fluid flow within the formation.The increased flow along fractures will lead to increased heatconvection. This again allows heater well spacing to be elongated in thedirection of increased heat convection.

Another geological factor that may be used in determining the directionof greatest thermal transfer efficiency is the direction of bedding inthe subsurface formation. In this respect, the most efficient thermaltransfer direction may be related to the direction of bedding of theformation. For example, in one embodiment the most efficient thermaltransfer direction is substantially in the plane of the bedding. Theplane of the bedding in FIG. 6 is defined by arrows 604 and 606.

Another factor that may be considered in the determination of mostefficient thermal transfer direction is the tilt of the subsurfaceformation. In certain cases, the direction along which thermal energywill travel through a subsurface formation most efficiently is along adirection of upward tilt of the subsurface formation relative to thesurface topography after pyrolysis has been instigated in the formation.Alternatively, the direction along which thermal energy will travelthrough a subsurface formation most efficiently is along a direction ofshortest relative distance between the local plane of the subsurfaceformation and the local plane of the surface topography. Thus, where aformation is tilted along a particular plane, the heater wells may beelongated in that direction. This is demonstrated in FIG. 7.

FIG. 7 provides another illustration of a portion of a shale oildevelopment area 700, demonstrating a well spacing arrangement of thepresent invention, in one embodiment. The development area 700represents a surface 702, and a subsurface formation 710. The formation710 is again an organic rich rock formation, such as oil shale.

The formation 710 of FIG. 7 has a direction in which thermal energytravels most efficiently. Arrow 704 demonstrates the illustrateddirection of most efficient travel for thermal energy. Arrow 706demonstrates a direction essentially normal to direction 704.

In the area 700 of FIG. 7, heater wells 730 are once again demonstrated.The heater wells 730 are again arranged in linear arrays, with eachheater well 730 having a wellbore 732 extending down to and completed inthe formation 710. Each wellbore 732 in the arrangement of FIG. 6 issubstantially vertical. However, the present inventions are not limitedto purely vertical wellbores 732.

It is noted that the heater wells 730 are farther apart in the directionof arrow 704, that is, most efficient thermal energy transfer, ascompared to the direction of arrow 706. This means that the heater wells730 are elongated along the direction in which thermal energy willtravel most efficiently through the subsurface formation 710. Onceagain, the elongation ratio may be about 1.2 to about 2.5.

Between the rows of heater wells 730 are once again production wells740. Each production well 740 also has a wellbore 742 extending down toand completed in the formation 710. The production wellbores 742 in thearrangement of FIG. 7 are substantially vertical.

The formation 710 of FIG. 7 has a thickness “t”. In this arrangement700, the thickness “t” is essentially constant. Thus, thickness “t₁” isshown at several places along the formation 710.

The formation 710 of FIG. 7 is tilted. This means that it is risingbeneath the surface 702. In the view of FIG. 7, the formation 710 istilted in the direction of arrow 704. This is indicated by the depth“d”. At one point, a distance from the surface 702 to the top of theformation 710 is at d₁. At another point in the formation 710, thedistance from the surface 702 to the top of the formation 710 is at d₂.Depth d₂ is greater than depth d₁.

To reflect the tilt in the formation 710 and the corresponding thermalefficiency, the heater wells 732 are spaced farther apart in thedirection of arrow 704 as compared to the direction of arrow 706. Thismeans that the heater wells 730 are elongated along the direction inwhich thermal energy will travel most efficiently through the subsurfaceformation 710.

It is recognized that in the field, formation depth is typicallymeasured against the surface 702 and not against sea level. Sea level isconsidered a constant, but the surface level is not. Therefore, in oneembodiment of the present inventions, the most efficient thermaltransfer direction is along the direction of shortest relative distancebetween the local plane of the subsurface formation and the local planeof the surface topography. This involves an analysis of the relativespacing of the subsurface formation 710 with the surface 702. In FIG. 7,this relative distance is changing in the direction of the tilt, thatis, arrow 704. Alternatively, the direction along which thermal energywill travel through a subsurface formation most efficiently is along adirection of shortest relative distance between the local plane of thesubsurface formation and sea level.

FIG. 6 provides a different dynamic. In this respect, the subsurfaceformation 610 has a changing thickness. Referring back to FIG. 6, it canbe seen that the shortest relative distance between the local plane ofthe subsurface formation 610 and the local plane of the surfacetopography 602 is at d₁. This is in the direction of arrow 604. This istrue even though the thickness “t” is increasing in the direction ofarrow 606. This may be due to either a tilt in the formation 610, achange in surface topography 602, or both. In any event, the directionof elongation for the heater wells 632 is along arrow 604.

As noted, heater wells in a shale oil development area such as heaterwells 630 may be completed substantially vertically. However, heaterwells may alternatively be deviated from a vertical axis. Still further,one or more of the heater wells may be completed substantiallyhorizontally, with the horizontal sections being substantially parallelto each other. The horizontal completions may be substantially along thedirection of most efficient thermal transfer, which in one embodimentmay be perpendicular to the direction of least horizontal principalstress in the formation. In another embodiment, the horizontalcompletions may be normal to the direction of most efficient thermaltransfer, which again may be perpendicular to the direction of leasthorizontal principal stress.

FIG. 8 is an illustration of a portion of a shale oil development area800, demonstrating a well spacing arrangement and using horizontalcompletions. The development area 800 represents a surface 802, and aformation 810. The formation 810 is an oil shale formation.

The formation 810 of FIG. 8 has a direction in which thermal energytravels most efficiently. Arrow 804 demonstrates the illustrateddirection of most efficient travel for thermal energy. Arrow 806demonstrates a direction normal to direction 804.

In order to produce hydrocarbons from the formation 810, a plurality ofheater wells 830 are once again provided. In the illustrativedevelopment area 800, the heater wells 830 are arranged in lineararrays. Each heater well 830 has a wellbore 832 extending down to andcompleted in the formation 810. However, in this arrangement 800, eachwellbore 832 is completed substantially horizontally. A horizontalportion of selected heater wells 830 is shown at 834.

The horizontal wellbores 834 are completed at substantially the samedepth within the formation 810. However, in another embodiment (notshown), a first plurality of the horizontal wellbores may be completedat substantially the same first depth, while a second plurality of thehorizontal wellbores is completed at a second depth. The completions atthe first depth and the completions at the second depth may bealternatingly spaced within the formation 810. They also may be spacedfurther apart in one direction than another. For example, in oneembodiment the horizontal completions 834 may be spaced farther aparthorizontally than vertically. The horizontal-to-vertical spacing ratiomay be based on a variety of factors. For example, thehorizontal-to-vertical spacing ratio may be at least equal to thehorizontal-to-vertical heat conductivity of the subsurface formation.

It is noted that the thermal conductivity in oil shales tends to begreater parallel to the bedding orientation than verticallyperpendicular to the bedding orientation. Thermal conductivity may be upto 30% greater parallel to the bedding orientation as compared tothermal conductivity perpendicular to the shale layer beddingorientation. Therefore, the horizontal heater wells 830 may be spacedfarther apart horizontally than vertically within an oil shaleformation. Stated another way, for horizontally completed wells, suchwells should be spaced closer together in the vertical direction(perpendicular to bedding) than horizontally (parallel to the plane ofthe bedding). In one embodiment, the horizontal-to-vertical spacingratio may be at least equal to the horizontal-to-vertical thermalconductivity ratio of the bedded oil shale. In one aspect, thehorizontal wells are completed in an orientation perpendicular to theshale layers.

In a related embodiment, the horizontal completions 834 may behydraulically fractured. At depths of greater than 1,000 feet, anddepending upon the various stresses at work in the formation 810, it isbelieved that artificial fractures will form vertically. In one aspect,the one or more artificial fractures form primarily along the directionof least principal stress in the oil shale formation. In one embodiment,the vertical fractures are propped to have a permeability of at least200 Darcy.

The heater wells 830 are optionally spaced farther apart in thedirection of arrow 804 as compared to the direction of arrow 806. Thismeans that the heater wells 832 are elongated along the direction inwhich thermal energy will travel most efficiently through the subsurfaceformation 810. However, heat transfer along the direction of thehorizontal wells is not as important where horizontal well length issimilar to the well spacing.

In FIG. 8, interspersed between the lines of heater wells 832 areproduction wells 840. Each production well 840 has a wellbore 842extending down to and completed in the formation 810. Here, eachwellbore 842 is substantially vertical. However, the production wells840 could also be completed horizontally.

In the development areas 600, 700, and 800, the heater wells 630, 730,830 are spaced linearly. However, in one aspect the plurality of heaterwells may comprise sets of well patterns aligned in the direction ofmost efficient thermal energy travel within the subsurface formation.Each well pattern also may include a production well completed throughthe formation. The patterns may include, but are not limited to, 3-spot,5-spot, 6-spot, or 7-spot patterns.

FIG. 9 presents a plan view of an illustrative heater well pattern 920in a shale oil development area 900. In this arrangement, a plurality of3-spot patterns 910 is joined to form a heater well pattern 920.Moreover, multiple heater well patterns 920 are further joined acrossthe shale oil development area 900.

Each 3-spot pattern 910 is comprised of three heater wells 930 and asingle production well 940. In the known 3-spot patterns, the triangleformed by the heater well or injection well is equilateral. However, inthe 3-spot patterns 910 of FIG. 9, the triangles are elongated.

The development area 900 is for the purpose of producing shale oil froma subsurface formation (such as formation 610 of FIG. 6). The formationhas a direction, shown at arrow 904, in which thermal energy travelsmost efficiently. Arrow 906 is transverse to arrow 904.

The distance between the heater wells 930 in the direction of arrow 904is indicated by d_(m). Distance d_(m) is representative of the spacingbetween the heater wells 930 in the direction in which thermal energywill travel most efficiently through the subsurface formation. Thedistance between the heater wells 930 in the direction of arrow 906 isindicated by d_(t). Direction d_(t) is representative of the directionthat is transverse to the direction in which thermal energy will travelmost efficiently through the subsurface formation. It can be seen thatdistance d_(m) is greater than distance d_(t). Thus, the heater wellpattern 920 is elongated in the direction of arrow 904.

Within certain of the 3-spot patterns 910 is a production well 940. Theproduction wells 940 receive hydrocarbons that have been converted as aresult of the application of heat by the heater wells 930. Theproduction wells 940 convey the hydrocarbons to the surface forprocessing in surface facilities such as facility 70 of FIG. 4. It isunderstood that the placement and number of production wells 940 is amatter of designer's choice.

It is also understood that the 3-spot patterns 910 are merelyillustrative; any repeating pattern of heater wells 930 may be used forthe methods of spacing heater wells herein. The patterns 910 mayalternately be 5-spot, 6-spot, 7-spot or other polygonal patterns. Thepatterns 910 may alternatively be substantially circular. It is alsounderstood that additional heater wells or additional production wells(not shown) may be placed around edges of the development area 900.

The above discussions of heater well arrangements 600, 700, 800 andpatterns 920 focus upon the elongation of wells to reflect the directionof most efficient thermal energy conveyance within a targeted subsurfaceformation. However, the arrangement of heater wells and production wellsmay also be adjusted to affect the ratio of gas-to-liquids production atsurface conditions. As hydrocarbons are generated from the immobilekerogen and begin to flow, the produced hydrocarbons may undergosecondary cracking if they remain for sufficient time in sufficientlyhot rock. Generally this is not desirable since a portion of theoil-like liquids will convert to gas (e.g., C₁-C₃ components) andimmobile coke. Gas is typically less valuable than oil, and theformation of coke indicates a loss of hydrocarbons. Secondary crackingis enhanced if a flow pathway of generated hydrocarbons takes it closerto a heater well than its point of origin. Thus, to maximize hydrocarbonliquids production (as compared to gas production), heater wells andproduction wells are preferably arranged such that the majority ofgenerated hydrocarbons can migrate to a production well by passing onlythrough monotonically decreasing temperatures.

In one embodiment, individual production wells are surrounded by, atmost, one layer of heater wells. This may include arrangements such as5-spot, 7-spot, or 9-spot arrays, with alternating rows of productionand heater wells. In another embodiment, two layers of heater wells maysurround a production well, but with the heater wells staggered so thata clear pathway exists for the majority of flow away from the furtherheater wells. “Clear pathway” may be functionally defined as asubstantially straight pathway between a heater well and a nearestproduction well which does not pass within one-quarter of the averageheater well-to-heater well spacing distance of another heater well. Flowand reservoir simulations may be employed to assess the pathways andtemperature history of hydrocarbon fluids generated in situ as theymigrate from their points of origin to production wells.

FIG. 10 provides a plan view of an illustrative heater well arrangementusing more than one layer of heater wells. The heater well arrangementis used in connection with the production of hydrocarbons from a shaleoil development area 1000. In FIG. 10, the heater well arrangementemploys a first layer of heater wells 1010, surrounded by a second layerof heater wells 1020. The heater wells in the first layer 1010 arereferenced at 1031, while the heater wells in the second layer 1020 arereferenced at 1032.

A production well 1040 is shown central to the well layers 1010 and1020. It is noted that the heater wells 1032 in the second layer 1020 ofwells are offset from the heater wells 1031 in the first layer 1010 ofwells, relative to the production well 1040. The purpose is to provide aflowpath for converted hydrocarbons that minimizes travel near a heaterwell in the first layer 1010 of heater wells. This, in turn, minimizessecondary cracking of hydrocarbons converted from kerogen ashydrocarbons flow from the second layer of wells 1020 to the productionwells 1040.

In the illustrative arrangement of FIG. 10, the first layer 1010 and thesecond layer 1020 each defines a 5-spot pattern. However, it isunderstood that other patterns may be employed, such as 3-spot or 6-spotpatterns. Further, it is understood that the pattern could be repeatedand elongated, such as in the direction of most efficient thermalconductivity. In any instance, a plurality of heater wells 1031comprising a first layer of heater wells 1010 is placed around aproduction well 1040, with a second plurality of heater wells 1032comprising a second layer of heater wells 1020 placed around the firstlayer 1010.

The heater wells in the two layers also may be arranged such that themajority of hydrocarbons generated by heat from each heater well 1032 inthe second layer 1020 are able to migrate to a production well 1040without passing substantially near a heater well 1031 in the first layer1010. The heater wells 1031, 1032 in the two layers 1010, 1020 furthermay be arranged such that the majority of hydrocarbons generated by heatfrom each heater well 1032 in the second layer 1020 are able to migrateto the production well 1040 without passing through a zone ofsubstantially increasing formation temperature.

Well pattern plans such as development areas 900 or 1000 may be combinedwith simulation specifically to assess flow paths and the impact ofsecondary cracking. Arranging production and heater wells to minimizesecondary thermal cracking may require lower ratios ofheater-to-production wells. For example, the ratio of heater wells toproduction wells may include ratios less than about 5:1. In someembodiments, the ratio of heater wells to production wells may be about4:1, 3:1, 1:1, or less.

Another way of formulating the arrangement of heater wells in a shaleoil (or other hydrocarbon) development area is to consider the rate atwhich the formation is heated downhole. Thus, in one embodiment of themethods for arranging heater wells herein, a plurality of substantiallyvertical heater wells may be completed through the subsurface formationwherein the heater wells are spaced around a production well such that aheat front emanating from each heater well reaches a production well atsubstantially the same time. The heater wells may be spaced in a patternaround the production well, including but not limited to, 3-spot,5-spot, 6-spot, and 7-spot patterns. The pattern may be elongated in aparticular direction, as described above, based upon the determineddirection of efficient thermal transfer. For example, the 3-spotpatterns 910 of FIG. 9 may reflect a point of convergence at theproduction wells 940 for the heat front.

In connection with the development of an oil shale field, it may bedesirable that the progression of heat through the subsurface inaccordance with steps 130 and 135 of FIG. 2 be uniform. However, forvarious reasons the heating and maturation of hydrocarbons in asubsurface formation may not proceed uniformly despite a regulararrangement of heater and production wells. Heterogeneities in the oilshale properties and formation structure may cause certain local areasto be more or less productive. Moreover, formation fracturing whichoccurs due to the heating and maturation of the oil shale can lead to anuneven distribution of preferred pathways and, thus, increase flow tocertain production wells and reduce flow to others. Uneven oil shalematuration may be an undesirable condition since certain subsurfaceregions may receive more heat energy than necessary where other regionsreceive less than desired. This, in turn, leads to the uneven flow andrecovery of production fluids. Produced oil quality, overall productionrate, and/or ultimate recoveries may be reduced.

To detect uneven flow conditions, production and heater wells may beinstrumented with sensors. Sensors may include equipment to measuretemperature, pressure, flow rates, and/or compositional information.Data from these sensors can be processed via simple rules or input todetailed simulations to reach decisions on how to adjust heater andproduction wells to improve subsurface performance. Therefore,production well performance may be adjusted by controlling backpressureor throttling on the well. Heater well performance may also be adjustedby controlling energy input. Sensor readings may also sometimes implymechanical problems with a well or downhole equipment which requiresrepair, replacement, or abandonment.

In one embodiment, flow rate, compositional, temperature and/or pressuredata are utilized from two or more wells as inputs to a computeralgorithm to control heating rate and/or production rates. Unmeasuredconditions at or in the neighborhood of the well are then estimated andused to control the well. For example, in situ fracturing behavior andkerogen maturation are estimated based on thermal, flow, andcompositional data from a set of wells. In another example, wellintegrity is evaluated based on pressure data, well temperature data,and estimated in situ stresses. In a related embodiment the number ofsensors is reduced by equipping only a subset of the wells withinstruments, and using the results to interpolate, calculate, orestimate conditions at uninstrumented wells. Certain wells may have onlya limited set of sensors (e.g., wellhead temperature and pressure only)where others have a much larger set of sensors (e.g., wellheadtemperature and pressure, bottomhole temperature and pressure,production composition, flow rate, electrical signature, casing strain,etc.).

A number of methods for spacing heater wells for an in situ conversionprocess are provided herein. Generally, one method includes the steps ofdetermining a direction along which thermal energy will travel mostefficiently through a subsurface formation, and completing a pluralityof heater wells in the subsurface formation. The heater wells are spacedfarther apart in the determined direction than in a direction transverseto the determined direction. Preferably, this and other methods areemployed when the subsurface formation is an oil shale formation,meaning that it comprises kerogen.

As noted, the step of determining a direction along which thermal energywill travel through the subsurface formation most efficiently may bebased upon a review of geological data pertaining to the subsurfaceformation. Typically, the geological data will include the direction ofleast horizontal principal stress in the subsurface formation. Usually,the direction along which thermal energy will travel through thesubsurface formation most efficiently is substantially perpendicular tothe direction of least horizontal principal stress.

In one aspect, the step of heating the subsurface formation formsthermally induced fractures. This increases the permeability of thesubsurface formation and aids in the subsurface flow of convertedhydrocarbons. The method may further include the steps of completing atleast one production well through the subsurface formation, andproducing hydrocarbons through the production wells. The productionwells may optionally also be aligned in the determined direction.

The methods described above may be aided through computer modeling. Inthis respect, the step of determining a direction along which thermalenergy will travel through the subsurface formation most efficiently maybe performed based upon computer modeling of characteristics of thesubsurface formation. Again, such characteristics may include thedirection of least horizontal principal stress in the subsurfaceformation. Alternately, or in addition, such characteristics may includethe direction of bedding in the subsurface formation. Othercharacteristics as outlined above may also be included in thecomputation, such as the tilt of the subsurface formation and surfacetopography, the organic carbon content of the kerogen, the hydrogenindex of the subsurface formation, the initial formation permeability,the depth of the subsurface formation, the thickness of the subsurfaceformation, and the modified Fischer Assay analyses. Such characteristicsmay include at least one derived fluid flow simulation and thermalgradient simulation.

As noted above, there are various methods for applying heat to anorganic-rich rock formation. For example, one method may includeelectrical resistance heaters disposed in a wellbore or outside of awellbore. One such method involves the use of electrical resistiveheating elements in a cased or uncased wellbore. Electrical resistanceheating involves directly passing electricity through a conductivematerial such that resistive losses cause it to heat the conductivematerial. Other heating methods include the use of downhole combustors,in situ combustion, radio-frequency (RF) electrical energy, or microwaveenergy. Still others include injecting a hot fluid into the oil shaleformation to directly heat it. The hot fluid may or may not becirculated. One method may include generating heat by burning a fuelexternal to or within a subsurface formation. For example, heat may besupplied by surface burners or downhole burners or by circulating hotfluids (such as methane gas or naphtha) into the formation through, forexample, wellbores via, for example, natural or artificial fractures.Some burners may be configured to perform flameless combustion.Alternatively, some methods may include combusting fuel within theformation such as via a natural distributed combustor, which generallyrefers to a heater that uses an oxidant to oxidize at least a portion ofthe carbon in the formation to generate heat, and wherein the oxidationtakes place in a vicinity proximate to a wellbore. The present methodsare not limited to the heating technique employed unless so stated inthe claims.

One method for formation heating involves the use of electricalresistors in which an electrical current is passed through a resistivematerial which dissipates the electrical energy as heat. This method isdistinguished from dielectric heating in which a high-frequencyoscillating electric current induces electrical currents in nearbymaterials and causes them to heat. The electric heater may include aninsulated conductor, an elongated member disposed in the opening, and/ora conductor disposed in a conduit. An early patent disclosing the use ofelectrical resistance heaters to produce oil shale in situ is U.S. Pat.No. 1,666,488. The '488 patent issued to Crawshaw in 1928. Since 1928,various designs for downhole electrical heaters have been proposed.Illustrative designs are presented in U.S. Pat. No. 1,701,884, U.S. Pat.No. 3,376,403, U.S. Pat. No. 4,626,665, U.S. Pat. No. 4,704,514, andU.S. Pat. No. 6,023,554).

A review of application of electrical heating methods for heavy oilreservoirs is given by R. Sierra and S. M. Farouq Ali, “PromisingProgress in Field Application of Reservoir Electrical Heating Methods”,Society of Petroleum Engineers Paper 69709, 2001. The entire disclosureof this reference is hereby incorporated by reference.

Certain previous designs for in situ electrical resistance heatersutilized solid, continuous heating elements (e.g., metal wires orstrips). However, such elements may lack the necessary robustness forlong-term, high temperature applications such as oil shale maturation.As the formation heats and the oil shale matures, significant expansionof the rock occurs. This leads to high stresses on wells intersectingthe formation. These stresses can lead to bending and stretching of thewellbore pipe and internal components. Cementing (e.g., U.S. Pat. No.4,886,118) or packing (e.g., U.S. Pat. No. 2,732,195) a heating elementin place may provide some protection against stresses, but some stressesmay still be transmitted to the heating element.

As an alternative, international patent publication WO 2005/010320teaches the use of electrically conductive fractures to heat the oilshale. A heating element is constructed by forming wellbores and thenhydraulically fracturing the oil shale formation around the wellbores.The fractures are filled with an electrically conductive material whichforms the heating element. Calcined petroleum coke is an exemplarysuitable conductant material. Preferably, the fractures are created in avertical orientation along longitudinal, horizontal planes formed byhorizontal wellbores. Electricity may be conducted through theconductive fractures from the heel to the toe of each well. Theelectrical circuit may be completed by an additional horizontal wellthat intersects one or more of the vertical fractures near the toe tosupply the opposite electrical polarity. The WO 2005/010320 processcreates an “in situ toaster” that artificially matures oil shale throughthe application of electric heat. Thermal conduction heats the oil shaleto conversion temperatures in excess of 300° C. causing artificialmaturation.

International patent publication WO 2005/045192 teaches an alternativeheating means that employs the circulation of a heated fluid within anoil shale formation. In the process of WO 2005/045192 supercriticalheated naphtha may be circulated through fractures in the formation.This means that the oil shale is heated by circulating a dense, hothydrocarbon vapor through sets of closely-spaced hydraulic fractures. Inone aspect, the fractures are horizontally formed and conventionallypropped. Fracture temperatures of 320°-400° C. are maintained for up tofive to ten years. Vaporized naptha may be the preferred heating mediumdue to its high volumetric heat capacity, ready availability andrelatively low degradation rate at the heating temperature. In the WO2005/045192 process, as the kerogen matures, fluid pressure will drivethe generated oil to the heated fractures, where it will be producedwith the cycling hydrocarbon vapor.

The purpose for heating the organic-rich rock formation is to pyrolyzeat least a portion of the solid formation hydrocarbons to createhydrocarbon fluids. The solid formation hydrocarbons may be pyrolyzed insitu by raising the organic-rich rock formation (or zones within theformation), to a pyrolyzation temperature. In certain embodiments, thetemperature of the formation may be slowly raised through the pyrolysistemperature range. For example, an in situ conversion process mayinclude heating at least a portion of the organic-rich rock formation toraise the average temperature of the zone above about 270° C. at a rateless than a selected amount (e.g., about 10° C., 5° C.; 3° C., 1° C.,0.5° C., or 0.1° C.) per day. In a further embodiment, the portion maybe heated such that an average temperature of the selected zone may beless than about 375° C. or, in some embodiments, less than about 400° C.The formation may be heated such that a temperature within the formationreaches (at least) an initial pyrolyzation temperature (e.g., atemperature at the lower end of the temperature range where pyrolyzationbegins to occur.

The pyrolysis temperature range may vary depending on the types offormation hydrocarbons within the formation, the heating methodology,and the distribution of heating sources. For example, a pyrolysistemperature range may include temperatures between about 270° C. andabout 900° C. Alternatively, the bulk of the target zone of theformation may be heated to between 300° to 600° C. In an alternativeembodiment, a pyrolysis temperature range may include temperaturesbetween about 270° C. to about 500° C.

Preferably, for in situ processes the heating of a production zone takesplace over a period of months, or even four or more years.Alternatively, the formation may be heated for one to fifteen years,alternatively, 3 to 10 years, 1.5 to 7 years, or 2 to 5 years. The bulkof the target zone of the formation may be heated to between 270° to800° C. Preferably, the bulk of the target zone of the formation isheated to between 300° to 600° C. Alternatively, the bulk of the targetzone is ultimately heated to a temperature below 400° C. (752° F.).

In certain embodiments of the methods of the present invention, downholeburners may be used to heat a targeted oil shale zone. Downhole burnersof various design have been discussed in the patent literature for usein oil shale and other largely solid hydrocarbon deposits. Examplesinclude U.S. Pat. No. 2,887,160; U.S. Pat. No. 2,847,071; U.S. Pat. No.2,895,555; U.S. Pat. No. 3,109,482; U.S. Pat. No. 3,225,829; U.S. Pat.No. 3,241,615; U.S. Pat. No. 3,254,721; U.S. Pat. No. 3,127,936; U.S.Pat. No. 3,095,031; U.S. Pat. No. 5,255,742; and U.S. Pat. No.5,899,269. Downhole burners operate through the transport of acombustible fuel (typically natural gas) and an oxidizer (typically air)to a subsurface position in a wellbore. The fuel and oxidizer reactdownhole to generate heat. The combustion gases are removed (typicallyby transport to the surface, but possibly via injection into theformation). Oftentimes, downhole burners utilize pipe-in-pipearrangements to transport fuel and oxidizer downhole, and then to removethe flue gas back up to the surface. Some downhole burners generate aflame, while others may not.

The use of downhole burners is an alternative to another form ofdownhole heat generation called steam generation. In downhole steamgeneration, a combustor in the well is used to boil water placed in thewellbore for injection into the formation. Applications of the downholeheat technology have been described in F. M. Smith, “A Down-holeburner—Versatile tool for well heating,” 25^(th) Technical Conference onPetroleum Production, Pennsylvania State University, pp 275-285 (Oct.19-21, 1966); H. Brandt, W. G. Poynter, and J. D. Hummell, “StimulatingHeavy Oil Reservoirs with Downhole Air-Gas Burners,” World Oil, pp.91-95 (September 1965); and C. I. DePriester and A. J. Pantaleo, “WellStimulation by Downhole Gas-Air Burner,” Journal of PetroleumTechnology, pp. 1297-1302 (December 1963).

Downhole burners have advantages over electrical heating methods due tothe reduced infrastructure cost. In this respect, there is no need foran expensive electrical power plant and distribution system. Moreover,there is increased thermal efficiency because the energy lossesinherently experienced during electrical power generation are avoided.

Few applications of downhole burners exist due to various design issues.Downhole burner design issues include temperature control and metallurgylimitations. In this respect, the flame temperature can overheat thetubular and burner hardware and cause them to fail via melting, thermalstresses, severe loss of tensile strength, or creep. Certain stainlesssteels, typically with high chromium content, can tolerate temperaturesup to ˜700° C. for extended periods. (See for example H. E. Boyer and T.L. Gall (eds.), Metals Handbook, “Chapter 16: Heat-Resistant Materials”,American Society for Metals, (1985.) The existence of flames can causehot spots within the burner and in the formation surrounding the burner.This is due to radiant heat transfer from the luminous portion of theflame. However, a typical gas flame can produce temperatures up to about1,650° C. Materials of construction for the burners must be sufficientto withstand the temperatures of these hot spots. The heaters aretherefore more expensive than a comparable heater without flames.

For downhole burner applications, heat transfer can occur in one ofseveral ways. These include conduction, convection, and radiativemethods. Radiative heat transfer can be particularly strong for an openflame. Additionally, the flue gases can be corrosive due to the CO₂ andwater content. Use of refractory metals or ceramics can help solve theseproblems, but typically at a higher cost. Ceramic materials withacceptable strength at temperatures in excess of 900° C. are generallyhigh alumina content ceramics. Other ceramics that may be useful includechrome oxide, zirconia oxide, and magnesium oxide based ceramics.Additionally, depending on the nature of the downhole combustion NO_(x)generation may be significant.

Heat transfer in a pipe-in-pipe arrangement for a downhole burner canalso lead to difficulties. The down going fuel and air will heatexchange with the up going hot flue gases. In a well there is minimalroom for a high degree of insulation and hence significant heat transferis typically expected. This cross heat exchange can lead to higher flametemperatures as the fuel and air become preheated. Additionally, thecross heat exchange can limit the transport of heat downstream of theburner since the hot flue gases may rapidly lose heat energy to therising cooler flue gases.

In the production of oil and gas resources, it may be desirable to usethe produced hydrocarbons as a source of power for ongoing operations.This may be applied to the development of oil and gas resources from oilshale. In this respect, when electrically resistive heaters are used inconnection with in situ shale oil recovery, large amounts of power arerequired.

Electrical power may be obtained from turbines that turn generators. Itmay be economically advantageous to power the gas turbines by utilizingproduced gas from the field. However, such produced gas must becarefully controlled so not to damage the turbine, cause the turbine tomisfire, or generate excessive pollutants (e.g., NO_(x)).

One source of problems for gas turbines is the presence of contaminantswithin the fuel. Contaminants include solids, water, heavy componentspresent as liquids, and hydrogen sulfide. Additionally, the combustionbehavior of the fuel is important. Combustion parameters to considerinclude heating value, specific gravity, adiabatic flame temperature,flammability limits, autoignition temperature, autoignition delay time,and flame velocity. Wobbe Index (WI) is often used as a key measure offuel quality. WI is equal to the ratio of the lower heating value to thesquare root of the gas specific gravity. Control of the fuel's WobbeIndex to a target value and range of, for example, ±10% or ±20% canallow simplified turbine design and increased optimization ofperformance.

Fuel quality control may be useful for shale oil developments where theproduced gas composition may change over the life of the field and wherethe gas typically has significant amounts of CO₂, CO, and H₂ in additionto light hydrocarbons. Commercial scale oil shale retorting is expectedto produce a gas composition that changes with time.

Inert gases in the turbine fuel can increase power generation byincreasing mass flow while maintaining a flame temperature in adesirable range. Moreover inert gases can lower flame temperature andthus reduce NO_(x) pollutant generation. Gas generated from oil shalematuration may have significant CO₂ content. Therefore, in certainembodiments of the production processes, the CO₂ content of the fuel gasis adjusted via separation or addition in the surface facilities tooptimize turbine performance.

Achieving a certain hydrogen content for low-BTU fuels may also bedesirable to achieve appropriate burn properties. In certain embodimentsof the processes herein, the H₂ content of the fuel gas is adjusted viaseparation or addition in the surface facilities to optimize turbineperformance. Adjustment of H₂ content in non-shale oil surfacefacilities utilizing low BTU fuels has been discussed in the patentliterature (e.g., U.S. Pat. No. 6,684,644 and U.S. Pat. No. 6,858,049,the entire disclosures of which are hereby incorporated by reference).

The process of heating formation hydrocarbons within an organic-richrock formation, for example, by pyrolysis, may generate fluids. Theheat-generated fluids may include water which is vaporized within theformation. In addition, the action of heating kerogen produces pyrolysisfluids which tend to expand upon heating. The produced pyrolysis fluidsmay include not only water, but also, for example, hydrocarbons, oxidesof carbon, ammonia, molecular nitrogen, and molecular hydrogen.Therefore, as temperatures within a heated portion of the formationincrease, a pressure within the heated portion may also increase as aresult of increased fluid generation, molecular expansion, andvaporization of water. Thus, some corollary exists between subsurfacepressure in an oil shale formation and the fluid pressure generatedduring pyrolysis. This, in turn, indicates that formation pressure maybe monitored to detect the progress of a kerogen conversion process.

The pressure within a heated portion of an organic-rich rock formationdepends on other reservoir characteristics. These may include, forexample, formation depth, distance from a heater well, a richness of theformation hydrocarbons within the organic-rich rock formation, thedegree of heating, and/or a distance from a producer well.

It may be desirable for the developer of an oil shale field to monitorformation pressure during development. Pressure within a formation maybe determined at a number of different locations. Such locations mayinclude, but may not be limited to, at a wellhead and at varying depthswithin a wellbore. In some embodiments, pressure may be measured at aproducer well. In an alternate embodiment, pressure may be measured at aheater well. In still another embodiment, pressure may be measureddownhole of a dedicated monitoring well.

The process of heating an organic-rich rock formation to a pyrolysistemperature range not only will increase formation pressure, but willalso increase formation permeability. The pyrolysis temperature rangeshould be reached before substantial permeability has been generatedwithin the organic-rich rock formation. An initial lack of permeabilitymay prevent the transport of generated fluids from a pyrolysis zonewithin the formation. In this manner, as heat is initially transferredfrom a heater well to an organic-rich rock formation, a fluid pressurewithin the organic-rich rock formation may increase proximate to thatheater well. Such an increase in fluid pressure may be caused by, forexample, the generation of fluids during pyrolysis of at least someformation hydrocarbons in the formation.

Alternatively, pressure generated by expansion of pyrolysis fluids orother fluids generated in the formation may be allowed to increase. Thisassumes that an open path to a production well or other pressure sinkdoes not yet exist in the formation. In one aspect, a fluid pressure maybe allowed to increase to or above a lithostatic stress. In thisinstance, fractures in the hydrocarbon containing formation may formwhen the fluid pressure equals or exceeds the lithostatic stress. Forexample, fractures may form from a heater well to a production well. Thegeneration of fractures within the heated portion may reduce pressurewithin the portion due to the production of produced fluids through aproduction well.

Once pyrolysis has begun within an organic-rich rock formation, fluidpressure may vary depending upon various factors. These include, forexample, thermal expansion of hydrocarbons, generation of pyrolysisfluids, rate of conversion, and withdrawal of generated fluids from theformation. For example, as fluids are generated within the formation,fluid pressure within the pores may increase. Removal of generatedfluids from the formation may then decrease the fluid pressure withinthe near wellbore region of the formation.

In certain embodiments, a mass of at least a portion of an organic-richrock formation may be reduced due, for example, to pyrolysis offormation hydrocarbons and the production of hydrocarbon fluids from theformation. As such, the permeability and porosity of at least a portionof the formation may increase. Any in situ method that effectivelyproduces oil and gas from oil shale will create permeability in what wasoriginally a very low permeability rock. The extent to which this willoccur is illustrated by the large amount of expansion that must beaccommodated if fluids generated from kerogen are unable to flow. Theconcept is illustrated in FIG. 3.

FIG. 5 provides a bar chart comparing one ton of Green River oil shalebefore 50 and after 51 a simulated in situ, retorting process. Thesimulated process was carried out at 2,400 psi and 750° F. on oil shalehaving a total organic carbon content of 22 wt. % and a Fisher assay of42 gallons/ton. Before the conversion, a total of 15.3 ft³ of rockmatrix 52 existed. This matrix comprised 7.2 ft³ of mineral 53, i.e.,dolomite, limestone, etc., and 8.1 ft³ of kerogen 54 imbedded within theshale. As a result of the conversion the material expanded to 26.1 ft³55. This represented 7.2 ft³ of mineral 56 (the same number as beforethe conversion), 6.6 ft³ of hydrocarbon liquid 57, 9.4 ft³ ofhydrocarbon vapor 58, and 2.9 ft³ of coke 59. It can be seen thatsubstantial volume expansion occurred during the conversion process.This, in turn, increases permeability of the rock structure.

In an embodiment, heating a portion of an organic-rich rock formation insitu to a pyrolysis temperature may increase permeability of the heatedportion. For example, permeability may increase due to formation ofthermal fractures within the heated portion caused by application ofheat. As the temperature of the heated portion increases, water may beremoved due to vaporization. The vaporized water may escape and/or beremoved from the formation. In addition, permeability of the heatedportion may also increase as a result of production of hydrocarbonfluids from pyrolysis of at least some of the formation hydrocarbonswithin the heated portion on a macroscopic scale.

Certain systems and methods described herein may be used to treatformation hydrocarbons in at least a portion of a relatively lowpermeability formation (e.g., in “tight” formations that containformation hydrocarbons). Such formation hydrocarbons may be heated topyrolyze at least some of the formation hydrocarbons in a selected zoneof the formation. Heating may also increase the permeability of at leasta portion of the selected zone. Hydrocarbon fluids generated frompyrolysis may be produced from the formation, thereby further increasingthe formation permeability.

Permeability of a selected zone within the heated portion of theorganic-rich rock formation may also rapidly increase while the selectedzone is heated by conduction. For example, permeability of animpermeable organic-rich rock formation may be less than about 0.1millidarcy before heating. In some embodiments, pyrolyzing at least aportion of organic-rich rock formation may increase permeability withina selected zone of the portion to greater than about 10 millidarcies,100 millidarcies, 1 Darcy, 10 Darcies, 20 Darcies, or 50 Darcies.Therefore, a permeability of a selected zone of the portion may increaseby a factor of more than about 10, 100, 1,000, 10,000, or 100,000. Inone embodiment, the organic-rich rock formation has an initial totalpermeability less than 1 millidarcy, alternatively less than 0.1 or 0.01millidarcies, before heating the organic-rich rock formation. In oneembodiment, the organic-rich rock formation has a post heating totalpermeability of greater than 1 millidarcy, alternatively, greater than10, 50 or 100 millidarcies, after heating the organic-rich rockformation.

In connection with heating the organic-rich rock formation, theorganic-rich rock formation may optionally be fractured to aid heattransfer or hydrocarbon fluid production. In one instance, fracturingmay be accomplished naturally by creating thermal fractures within theformation through application of heat. Thermal fracture formation iscaused by thermal expansion of the rock and fluids and by chemicalexpansion of kerogen transforming into oil and gas. Thermal fracturingcan occur both in the immediate region undergoing heating, and in coolerneighboring regions. The thermal fracturing in the neighboring regionsis due to propagation of fractures and tension stresses developed due tothe expansion in the hotter zones. Thus, by both heating theorganic-rich rock and transforming the kerogen to oil and gas, thepermeability is increased not only from fluid formation andvaporization, but also via thermal fracture formation. The increasedpermeability aids fluid flow within the formation and production of thehydrocarbon fluids generated from the kerogen.

In addition, a process known as hydraulic fracturing may be used.Hydraulic fracturing is a process known in the art of oil and gasrecovery where a fracture fluid is pressurized within the wellbore abovethe fracture pressure of the formation, thus developing fracture planeswithin the formation to relieve the pressure generated within thewellbore. Hydraulic fractures may be used to create additionalpermeability and/or be used to provide an extended geometry for a heaterwell. The WO 2005/010320 patent publication incorporated above describesone such method.

In connection with the production of hydrocarbons from a rock matrix,particularly those of shallow depth, a concern may exist with respect toearth subsidence. This is particularly true in the in situ heating oforganic-rich rock where a portion of the matrix itself is thermallyconverted and removed. Initially, the formation may contain formationhydrocarbons in solid form, such as, for example, kerogen. The formationmay also initially contain water-soluble minerals. Initially, theformation may also be substantially impermeable to fluid flow.

The in situ heating of the matrix pyrolyzes at least a portion of theformation hydrocarbons to create hydrocarbon fluids. This, in turn,creates permeability within a matured (pyrolyzed) organic-rich rock zonein the organic-rich rock formation. The combination of pyrolyzation andincreased permeability permits hydrocarbon fluids to be produced fromthe formation. At the same time, the loss of supporting matrix materialalso creates the potential for subsidence relative to the earth surface.

In some instances, subsidence is sought to be minimized in order toavoid environmental or hydrogeological impact. In this respect, changingthe contour and relief of the earth surface, even by a few inches, canchange runoff patterns, affect vegetation patterns, and impactwatersheds. In addition, subsidence has the potential of damagingproduction or heater wells formed in a production area. Such subsidencecan create damaging hoop and compressional stresses on wellbore casings,cement jobs, and equipment downhole.

In order to avoid or minimize subsidence, it is proposed to leaveselected portions of the formation hydrocarbons substantiallyunpyrolyzed. This serves to preserve one or more unmatured, organic-richrock zones. In some embodiments, the unmatured organic-rich rock zonesmay be shaped as substantially vertical pillars extending through asubstantial portion of the thickness of the organic-rich rock formation.

The heating rate and distribution of heat within the formation may bedesigned and implemented to leave sufficient unmatured pillars toprevent subsidence. In one aspect, heat injection wellbores are formedin a pattern such that untreated pillars of oil shale are lefttherebetween to support the overburden and prevent subsidence.

It is preferred that thermal recovery of oil and gas be conducted beforeany solution mining of nahcolite or other water-soluble minerals presentin the formation. Solution mining can generate large voids in a rockformation and collapse breccias in an oil shale development area. Thesevoids and brecciated zones may pose problems for in situ and miningrecovery of oil shale, further increasing the utility of supportingpillars.

In some embodiments, compositions and properties of the hydrocarbonfluids produced by an in situ conversion process may vary depending on,for example, conditions within an organic-rich rock formation.Controlling heat and/or heating rates of a selected section in anorganic-rich rock formation may increase or decrease production ofselected produced fluids.

In one embodiment, operating conditions may be determined by measuringat least one property of the organic-rich rock formation. The measuredproperties may be input into a computer executable program. At least oneproperty of the produced fluids selected to be produced from theformation may also be input into the computer executable program. Theprogram may be operable to determine a set of operating conditions fromat least the one or more measured properties. The program may also beconfigured to determine the set of operating conditions from at leastone property of the selected produced fluids. In this manner, thedetermined set of operating conditions may be configured to increaseproduction of selected produced fluids from the formation.

Certain heater well embodiments may include an operating system that iscoupled to any of the heater wells such as by insulated conductors orother types of wiring. The operating system may be configured tointerface with the heater well. The operating system may receive asignal (e.g., an electromagnetic signal) from a heater that isrepresentative of a temperature distribution of the heater well.Additionally, the operating system may be further configured to controlthe heater well, either locally or remotely. For example, the operatingsystem may alter a temperature of the heater well by altering aparameter of equipment coupled to the heater well. Therefore, theoperating system may monitor, alter, and/or control the heating of atleast a portion of the formation.

In some embodiments, a heater well may be turned down and/or off afteran average temperature in a formation may have reached a selectedtemperature. Turning down and/or off the heater well may reduce inputenergy costs, substantially inhibit overheating of the formation, andallow heat to substantially transfer into colder regions of theformation.

Temperature (and average temperatures) within a heated organic-rich rockformation may vary, depending on, for example, proximity to a heaterwell, thermal conductivity and thermal diffusivity of the formation,type of reaction occurring, type of formation hydrocarbon, and thepresence of water within the organic-rich rock formation. At points inthe field where monitoring wells are established, temperaturemeasurements may be taken directly in the wellbore. Further, at heaterwells the temperature of the immediately surrounding formation is fairlywell understood. However, it is desirable to interpolate temperatures topoints in the formation intermediate temperature sensors and heaterwells.

In accordance with one aspect of the production processes of the presentinventions, a temperature distribution within the organic-rich rockformation may be computed using a numerical simulation model. Thenumerical simulation model may calculate a subsurface temperaturedistribution through interpolation of known data points and assumptionsof formation conductivity. In addition, the numerical simulation modelmay be used to determine other properties of the formation under theassessed temperature distribution. For example, the various propertiesof the formation may include, but are not limited to, permeability ofthe formation.

The numerical simulation model may also include assessing variousproperties of a fluid formed within an organic-rich rock formation underthe assessed temperature distribution. For example, the variousproperties of a formed fluid may include, but are not limited to, acumulative volume of a fluid formed in the formation, fluid viscosity,fluid density, and a composition of the fluid formed in the formation.Such a simulation may be used to assess the performance of acommercial-scale operation or small-scale field experiment. For example,a performance of a commercial-scale development may be assessed basedon, but not limited to, a total volume of product that may be producedfrom a research-scale operation.

Some embodiments include producing at least a portion of the hydrocarbonfluids from the organic-rich rock formation. The hydrocarbon fluids maybe produced through production wells. Production wells may be cased oruncased wells and drilled and completed through methods known in theart.

Some embodiments further include producing a production fluid from theorganic-rich rock formation where the production fluid contains thehydrocarbon fluids and an aqueous fluid. The aqueous fluid may containwater-soluble minerals and/or migratory contaminant species. In suchcase, the production fluid may be separated into a hydrocarbon streamand an aqueous stream at a surface facility. Thereafter thewater-soluble minerals and/or migratory contaminant species may berecovered from the aqueous stream. This embodiment may be combined withany of the other aspects of the invention discussed herein.

The produced hydrocarbon fluids may include a pyrolysis oil component(or condensable component) and a pyrolysis gas component (ornon-condensable component). Condensable hydrocarbons produced from theformation will typically include paraffins, cycloalkanes,mono-aromatics, and di-aromatics as components. Such condensablehydrocarbons may also include other components such as tri-aromatics andother hydrocarbon species.

In certain embodiments, a majority of the hydrocarbons in the producedfluid may have a carbon number of less than approximately 25.Alternatively, less than about 15 weight % of the hydrocarbons in thefluid may have a carbon number greater than approximately 25. Thenon-condensable hydrocarbons may include, but are not limited to,hydrocarbons having carbon numbers less than 5.

In certain embodiments, the API gravity of the condensable hydrocarbonsin the produced fluid may be approximately 20 or above (e.g., 25, 30,40, 50, etc.). In certain embodiments, the hydrogen to carbon atomicratio in produced fluid may be at least approximately 1.7 (e.g., 1.8,1.9, etc.).

Some production procedures include in situ heating of an organic-richrock formation that contains both formation hydrocarbons and formationwater-soluble minerals prior to substantial removal of the formationwater-soluble minerals from the organic-rich rock formation. In someembodiments of the invention there is no need to partially,substantially or completely remove the water-soluble minerals prior toin situ heating. For example, in an oil shale formation that containsnaturally occurring nahcolite, the oil shale may be heated prior tosubstantial removal of the nahcolite by solution mining. Substantialremoval of a water-soluble mineral may represent the degree of removalof a water-soluble mineral that occurs from any commercial solutionmining operation as known in the art. Substantial removal of awater-soluble mineral may be approximated as removal of greater than 5weight percent of the total amount of a particular water-soluble mineralpresent in the zone targeted for hydrocarbon fluid production in theorganic-rich rock formation. In alternative embodiments, in situ heatingof the organic-rich rock formation to pyrolyze formation hydrocarbonsmay be commenced prior to removal of greater than 3 weight percent,alternatively 7 weight percent, 10 weight percent or 13 weight percentof the formation water-soluble minerals from the organic-rich rockformation.

The impact of heating oil shale to produce oil and gas prior toproducing nahcolite is to convert the nahcolite to a more recoverableform (soda ash), and provide permeability facilitating its subsequentrecovery. Water-soluble mineral recovery may take place as soon as theretorted oil is produced, or it may be left for a period of years forlater recovery. If desired, the soda ash can be readily converted backto nahcolite on the surface. The ease with which this conversion can beaccomplished makes the two minerals effectively interchangeable.

In some production processes, heating the organic-rich rock formationincludes generating soda ash by decomposition of nahcolite. The methodmay include processing an aqueous solution containing water-solubleminerals in a surface facility to remove a portion of the water-solubleminerals. The processing step may include removing the water-solubleminerals by precipitation caused by altering the temperature of theaqueous solution.

The water-soluble minerals may include sodium. The water-solubleminerals may also include nahcolite (sodium bicarbonate), soda ash(sodium carbonate), dawsonite (NaAl(CO₃)(OH)₂), or combinations thereof.The surface processing may further include converting the soda ash backto sodium bicarbonate (nahcolite) in the surface facility by reactionwith CO₂. After partial or complete removal of the water-solubleminerals, the aqueous solution may be reinjected into a subsurfaceformation where it may be sequestered. The subsurface formation may bethe same as or different from the original organic-rich rock formation.

In some production processes, heating of the organic-rich rock formationboth pyrolyzes at least a portion of the formation hydrocarbons tocreate hydrocarbon fluids and makes available migratory contaminantspecies previously bound in the organic-rich rock formation. Themigratory contaminant species may be formed through pyrolysis of theformation hydrocarbons, may be liberated from the formation itself uponheating, or may be made accessible through the creation of increasedpermeability upon heating of the formation. The migratory contaminantspecies may be soluble in water or other aqueous fluids present in orinjected into the organic-rich rock formation.

Producing hydrocarbons from pyrolyzed oil shale will generally leavebehind some migratory contaminant species which are at least partiallywater-soluble. Depending on the hydrological connectivity of thepyrolyzed shale oil to shallower zones, these components may eventuallymigrate into ground water in concentrations which are environmentallyunacceptable. The types of potential migratory contaminant speciesdepend on the nature of the oil shale pyrolysis and the composition ofthe oil shale being converted. If the pyrolysis is performed in theabsence of oxygen or air, the contaminant species may include aromatichydrocarbons (e.g. benzene, toluene, ethylbenzene, xylenes),polyaromatic hydrocarbons (e.g. anthracene, pyrene, naphthalene,chrysene), metal contaminants (e.g. As, Co, Pb, Mo, Ni, and Zn), andother species such as sulfates, ammonia, Al, K, Mg, chlorides, flouridesand phenols. If oxygen or air is employed, contaminant species may alsoinclude ketones, alcohols, and cyanides. Further, the specific migratorycontaminant species present may include any subset or combination of theabove-described species.

It may be desirable for a field developer to assess the connectivity ofthe organic-rich rock formation to aquifers. This may be done todetermine if, or to what extent, in situ pyrolysis of formationhydrocarbons in the organic-rich rock formation may create migratoryspecies with the propensity to migrate into an aquifer. If theorganic-rich rock formation is hydrologically connected to an aquifer,precautions may be taken to reduce or prevent species generated orliberated during pyrolysis from entering the aquifer. Alternatively, theorganic-rich rock formation may be flushed with water or an aqueousfluid after pyrolysis as described herein to remove water-solubleminerals and/or migratory contaminant species. In other embodiments, theorganic-rich rock formation may be substantially hydrologicallyunconnected to any source of ground water. In such a case, flushing theorganic-rich rock formation may not be desirable for removal ofmigratory contaminant species but may nevertheless be desirable forrecovery of water-soluble minerals.

Following production of hydrocarbons from an organic-rich formation,some migratory contaminant species may remain in the rock formation. Insuch case, it may be desirable to inject an aqueous fluid into theorganic-rich rock formation and have the injected aqueous fluid dissolveat least a portion of the water-soluble minerals and/or the migratorycontaminant species to form an aqueous solution. The aqueous solutionmay then be produced from the organic-rich rock formation through, forexample, solution production wells. The aqueous fluid may be adjusted toincrease the solubility of the migratory contaminant species and/or thewater-soluble minerals. The adjustment may include the addition of anacid or base to adjust the pH of the solution. The resulting aqueoussolution may then be produced from the organic-rich rock formation tothe surface for processing.

After initial aqueous fluid production, it may further be desirable toflush the matured organic-rich rock zone and the unmatured organic-richrock zone with an aqueous fluid. The aqueous fluid may be used tofurther dissolve water-soluble minerals and migratory contaminantspecies. The flushing may optionally be completed after a substantialportion of the hydrocarbon fluids have been produced from the maturedorganic-rich rock zone. In some embodiments, the flushing step may bedelayed after the hydrocarbon fluid production step. The flushing may bedelayed to allow heat generated from the heating step to migrate deeperinto surrounding unmatured organic-rich rock zones to convert nahcolitewithin the surrounding unmatured organic-rich rock zones to soda ash.Alternatively, the flushing may be delayed to allow heat generated fromthe heating step to generate permeability within the surroundingunmatured organic-rich rock zones. Further, the flushing may be delayedbased on current and/or forecast market prices of sodium bicarbonate,soda ash, or both as further discussed herein. This method may becombined with any of the other aspects of the invention as discussedherein

Upon flushing of an aqueous solution, it may be desirable to process theaqueous solution in a surface facility to remove at least some of themigratory contaminant species. The migratory contaminant species may beremoved through use of, for example, an adsorbent material, reverseosmosis, chemical oxidation, bio-oxidation, and/or ion exchange.Examples of these processes are individually known in the art. Exemplaryadsorbent materials may include activated carbon, clay, or fuller'searth.

In certain areas with oil shale resources, additional oil shaleresources or other hydrocarbon resources may exist at lower depths.Other hydrocarbon resources may include natural gas in low permeabilityformations (so-called “tight gas”) or natural gas trapped in andadsorbed on coal (so called “coalbed methane”). In some embodiments withmultiple shale oil resources it may be advantageous to develop deeperzones first and then sequentially shallower zones. In this way, wellswill need not cross hot zones or zones of weakened rock. In otherembodiments in may be advantageous to develop deeper zones by drillingwells through regions being utilized as pillars for shale oildevelopment at a shallower depth.

Simultaneous development of shale oil resources and natural gasresources in the same area can synergistically utilize certain facilityand logistic operations. For example, gas treating may be performed at asingle plant. Likewise personnel may be shared among the developments.

FIG. 4 illustrates a schematic diagram of an embodiment of surfacefacilities 470 that may be configured to treat a produced fluid. Theproduced fluid 485 may be produced from the subsurface formation 484though a production well 471 as described herein. The produced fluid mayinclude any of the produced fluids produced by any of the methods asdescribed herein. The subsurface formation 484 may be any subsurfaceformation, including, for example, an organic-rich rock formationcontaining any of oil shale, coal, or tar sands for example. Aproduction scheme may involve quenching 472 produced fluids to atemperature below 300° F., 200° F., or even 100° F., separating outcondensable components (i.e., oil 474 and water 475) in an oil separator473, treating the noncondensable components 476 (i.e. gas) in a gastreating unit 477 to remove water 478 and sulfur species 479, removingthe heavier components from the gas (e.g., propane and butanes) in a gasplant 481 to form liquid petroleum gas (LPG) 480 for sale, andgenerating electrical power 482 in a power plant 488 from the remaininggas 483. The electrical power 482 may be used as an energy source forheating the subsurface formation 484 through any of the methodsdescribed herein. For example, the electrical power 482 may be fed at ahigh voltage, for example 132 kV, to a transformer 86 and stepped downto a lower voltage, for example 6600 V, before being fed to anelectrical resistance heater element located in a heater well 487located in the subsurface formation 484. In this way all or a portion ofthe power required to heat the subsurface formation 484 may be generatedfrom the non-condensable portion of the produced fluids 485. Excess gas,if available, may be exported for sale.

Produced fluids from in situ oil shale production contain a number ofcomponents which may be separated in surface facilities. The producedfluids typically contain water, noncondensable hydrocarbon alkanespecies (e.g., methane, ethane, propane, n-butane, isobutane),noncondensable hydrocarbon alkene species (e.g., ethene, propene),condensable hydrocarbon species composed of (alkanes, olefins,aromatics, and polyaromatics among others), CO₂, CO, H₂, H₂S, and NH₃.

In a surface facility, condensable components may be separated fromnon-condensable components by reducing temperature and/or increasingpressure. Temperature reduction may be accomplished using heatexchangers cooled by ambient air or available water. Alternatively, thehot produced fluids may be cooled via heat exchange with producedhydrocarbon fluids previously cooled. The pressure may be increased viacentrifugal or reciprocating compressors. Alternatively, or inconjunction, a diffuser-expander apparatus may be used to condense outliquids from gaseous flows. Separations may involve several stages ofcooling and/or pressure changes.

Water in addition to condensable hydrocarbons may be dropped out of thegas when reducing temperature or increasing pressure. Liquid water maybe separated from condensed hydrocarbons via gravity settling vessels orcentrifugal separators. Demulsifiers may be used to aid in waterseparation.

Methods to remove CO₂, as well as other so-called acid gases (such asH₂S), from produced hydrocarbon gas include the use of chemical reactionprocesses and of physical solvent processes. Chemical reaction processestypically involve contacting the gas stream with an aqueous aminesolution at high pressure and/or low temperature. This causes the acidgas species to chemically react with the amines and go into solution. Byraising the temperature and/or lowering the pressure, the chemicalreaction can be reversed and a concentrated stream of acid gases can berecovered. An alternative chemical reaction process involves hotcarbonate solutions, typically potassium carbonate. The hot carbonatesolution is regenerated and the concentrated stream of acid gases isrecovered by contacting the solution with steam. Physical solventprocesses typically involve contacting the gas stream with a glycol athigh pressure and/or low temperature. Like the amine processes, reducingthe pressure or raising the temperature allows regeneration of thesolvent and recovery of the acid gases. Certain amines or glycols may bemore or less selective in the types of acid gas species removed. Sizingof any of these processes requires determining the amount of chemical tocirculate, the rate of circulation, the energy input for regeneration,and the size and type of gas-chemical contacting equipment. Contactingequipment may include packed or multi-tray countercurrent towers.Optimal sizing for each of these aspects is highly dependent on the rateat which gas is being produced from the formation and the concentrationof the acid gases in the gas stream.

Acid gas removal may also be effectuated through the use of distillationtowers. Such towers may include an intermediate freezing section whereinfrozen CO₂ and H₂S particles are allowed to form. A mixture of frozenparticles and liquids fall downward into a stripping section, where thelighter hydrocarbon gasses break out and rise within the tower. Arectification section may be provided at an upper end of the tower tofurther facilitate the cleaning of the overhead gas stream.

The hydrogen content of a gas stream may be adjusted by either removingall or a portion of the hydrogen or by removing all or a portion of thenon-hydrogen species (e.g., CO₂, CH₄, etc.) Separations may beaccomplished using cryogenic condensation, pressure-swing ortemperature-swing adsorption, or selective diffusion membranes. Ifadditional hydrogen is needed, hydrogen may be made by reforming methanevia the classic water-shift reaction.

CONCLUSION

The above-described processes may be of merit in connection with therecovery of hydrocarbons in the Piceance Basin of Colorado. Some haveestimated that in some oil shale deposits of the Western United States,up to 1 million barrels of oil may be recoverable per surface acre. Onestudy has estimated the oil shale resource within the nahcolite-bearingportions of the oil shale formations of the Piceance Basin to be 400billion barrels of shale oil in place. Overall, up to 1 trillion barrelsof shale oil may exist in the Piceance Basin alone.

Certain features of the present invention are described in terms of aset of numerical upper limits and a set of numerical lower limits. Itshould be appreciated that ranges formed by any combination of theselimits are within the scope of the invention unless otherwise indicated.Although some of the dependent claims have single dependencies inaccordance with U.S. practice, each of the features in any of suchdependent claims can be combined with each of the features of one ormore of the other dependent claims dependent upon the same independentclaim or claims.

While it will be apparent that the invention herein described is wellcalculated to achieve the benefits and advantages set forth above, itwill be appreciated that the invention is susceptible to modification,variation and change without departing from the spirit thereof.

1. A method for spacing heater wells for an in situ conversion process in a subsurface formation comprising oil shale, the method comprising: determining a direction along which thermal energy will travel most efficiently through the subsurface formation; and completing a plurality of heater wells in the subsurface formation, the heater wells being spaced farther apart in the determined direction than in a direction transverse to the determined direction.
 2. The method of claim 1, wherein the step of determining a direction along which thermal energy will travel through the subsurface formation most efficiently is performed based upon a review of geological data pertaining to the subsurface formation.
 3. The method of claim 2, wherein the geological data comprises the direction of least horizontal principal stress in the subsurface formation.
 4. The method of claim 3, wherein the direction along which thermal energy will travel through the subsurface formation most efficiently is substantially perpendicular to the direction of least horizontal principal stress.
 5. The method of claim 3, wherein the direction along which thermal energy will travel through the subsurface formation most efficiently is substantially parallel to the direction of least horizontal principal stress.
 6. The method of claim 2, wherein the geological data comprises the direction of bedding in the subsurface formation.
 7. The method of claim 6, wherein the direction along which thermal energy will travel through the subsurface formation most efficiently is substantially along the direction of bedding of the subsurface formation.
 8. The method of claim 2, wherein the geological data comprises the tilt of the subsurface formation and the relative spacing with the surface topography.
 9. The method of claim 8, wherein the direction along which thermal energy will travel through the subsurface formation most efficiently is along a direction of upward tilt of the subsurface formation relative to the surface topography.
 10. The method of claim 8, wherein the direction along which thermal energy will travel through the subsurface formation most efficiently is along a direction of upward tilt of the subsurface formation relative to sea level.
 11. The method of claim 8, wherein the direction along which thermal energy will travel through the subsurface formation most efficiently is along a direction of shortest relative distance between the local plane of the subsurface formation and the local plane of the surface topography.
 12. The method of claim 8, wherein the direction along which thermal energy will travel through the subsurface formation most efficiently is along a direction of shortest relative distance between the local plane of the subsurface formation and sea level.
 13. The method of claim 1, wherein the step of determining a direction along which thermal energy will travel through the subsurface formation most efficiently is performed based upon a review of formation temperature gradient data from previous in situ conversion processes in other areas of the subsurface formation.
 14. The method of claim 1, wherein the geological data comprises at least one of the organic carbon content of the kerogen, hydrogen index of the subsurface formation, initial formation permeability, depth of the subsurface formation, thickness of the subsurface formation, heterogeneity of rock in the subsurface formation, and modified Fischer Assay analyses.
 15. The method of claim 1, wherein the heater wells are substantially vertical.
 16. The method of claim 1, wherein: the plurality of heater wells are completed with a substantially horizontal wellbore, the horizontal wellbores being substantially parallel to each other; and each horizontal wellbore is completed substantially in the direction of least horizontal principal stress in the subsurface formation.
 17. The method of claim 1, wherein: the plurality of heater wells are completed with a substantially horizontal wellbore, the horizontal wellbores being substantially parallel to each other; and each horizontal wellbore is completed substantially in a direction normal to the least horizontal principal stress in the subsurface formation.
 18. The method of claim 1, wherein: selected first heater wells have a horizontal wellbore completed at a first depth in the subsurface formation, and selected second heater wells have a horizontal wellbore completed at a second depth in the subsurface formation; and the first and second heater wells are alternatingly spaced within the subsurface formation, and are spaced farther apart horizontally than vertically.
 19. The method of claim 1, further comprising: heating the subsurface formation in order to form thermally induced fractures.
 20. The method of claim 2, further comprising the steps of: completing at least one production well through the subsurface formation; producing hydrocarbons through the at least one production well; and wherein the at least one production well comprises a plurality of production wells also aligned in the determined direction.
 21. The method of claim 1, wherein: the plurality of heater wells comprise sets of a repeating well pattern elongated in the determined direction; each set of repeating well patterns has a production well completed through the surface formation; and the sets of well patterns each have a production well completed through the surface formation.
 22. The method of claim 21, wherein the patterns of heater wells are 3-spot patterns, 5-spot patterns, 6-spot patterns or 7-spot patterns.
 23. The method of claim 21, wherein the patterns of heater wells comprise a first pattern around a corresponding production well, and a second pattern around the first pattern.
 24. The method of claim 21, wherein the repeating well pattern elongated in the determined direction defines an elongation ratio of about 1.20 to 2.50.
 25. A method for arranging heater wells for an in situ kerogen conversion process, comprising: providing a production well; completing a plurality of heater wells around the production well, the plurality of heater wells comprising a first layer of heater wells around the production well, and a second layer of heater wells around the first layer; wherein the heater wells in the second layer of wells are arranged relative to the heater wells in the first layer of wells so as to minimize secondary cracking of hydrocarbons converted from the kerogen as the hydrocarbons flow from the second layer of wells to the production well; and wherein the plurality of heater wells and the production well are arranged such that the majority of hydrocarbons generated by heat from each heater well is able to migrate to the production well without passing through a zone of substantially increasing formation temperature. 